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, 2006

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 P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348 (610) 765-5959	23-3064219
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

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  ¨
Exelon Generation Company, LLC	Yes  ¨	No  x
Commonwealth Edison Company	Yes  x	No  ¨
PECO Energy Company	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
Exelon Generation Company, LLC	Yes  x	No  ¨
Commonwealth Edison Company	Yes  ¨	No  x
PECO Energy Company	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 a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Act).

	Large Accelerated	Accelerated	Non-Accelerated
Exelon Corporation	X
Exelon Generation Company, LLC			X
Commonwealth Edison Company			X
PECO Energy Company			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
Exelon Generation Company, LLC	Yes  ¨	No  x
Commonwealth Edison Company	Yes  ¨	No  x
PECO Energy Company	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, 2006, was as follows:

Exelon Corporation Common Stock, without par value	$38,019,493,399
Exelon Generation Company, LLC	Not applicable
Commonwealth Edison Company Common Stock, $12.50 par value	No established market
PECO Energy Company Common Stock, without par value	None

The number of shares outstanding of each registrant’s common stock as of January 31, 2007 was as follows:

Exelon Corporation Common Stock, without par value	670,157,335
Exelon Generation Company, LLC	Not applicable
Commonwealth Edison Company Common Stock, $12.50 par value	127,016,519
PECO Energy Company Common Stock, without par value	170,478,507

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
	Exelon Generation Company, LLC	3
	Commonwealth Edison Company	15
	PECO Energy Company	15
	Employees	20
	Environmental Regulation	21
	Managing the Risks in the Business	27
	Executive Officers of the Registrants	31
ITEM 1A.	RISK FACTORS	33
	Exelon Corporation	33
	Exelon Generation Company, LLC	35
	Commonwealth Edison Company	41
	PECO Energy Company	41
ITEM 1B.	UNRESOLVED STAFF COMMENTS	51
ITEM 2.	PROPERTIES	51
	Exelon Generation Company, LLC	51
	Commonwealth Edison Company	53
	PECO Energy Company	53
ITEM 3.	LEGAL PROCEEDINGS	54
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	54
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	55
ITEM 6.	SELECTED FINANCIAL DATA	57
	Exelon Corporation	57
	Exelon Generation Company, LLC	59
	Commonwealth Edison Company	60
	PECO Energy Company	61
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION	62
	Exelon Corporation	62
	Exelon Generation Company, LLC	143
	Commonwealth Edison Company	145
	PECO Energy Company	147
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	134
	Exelon Corporation	134
	Exelon Generation Company, LLC	144
	Commonwealth Edison Company	146
	PECO Energy Company	148
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	149
	Exelon Corporation	149

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		Page No.
	Exelon Generation Company, LLC	152
	Commonwealth Edison Company	153
	PECO Energy Company	154
	Combined Notes to Consolidated Financial Statements	179
	1. Significant Policies	179
	2. Acquisitions and Dispositions	204
	3. Discontinued Operations	209
	4. Regulatory Issues	210
	5. Accounts Receivable	221
	6. Property, Plant and Equipment	222
	7. Jointly Owned Electric Utility Plant	224
	8. Intangible Assets	224
	9. Fair Value of Financial Assets and Liabilities	227
	10. Severance Accounting	238
	11. Debt and Credit Agreements	239
	12. Income Taxes	247
	13. Asset Retirement Obligations	254
	14. Retirement Benefits	263
	15. Preferred Securities	275
	16. Common Stock	276
	17. Earnings Per Share	278
	18. Commitments and Contingencies	278
	19. Supplemental Financial Information	297
	20. Segment Information	312
	21. Related Party Transactions	313
	22. Quarterly Data	322
	23. Subsequent Events	324
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	325
ITEM 9A.	CONTROLS AND PROCEDURES	325
	Exelon Corporation	325
	Exelon Generation Company, LLC	325
	Commonwealth Edison Company	325
	PECO Energy Company	325
ITEM 9B.	OTHER INFORMATION	325
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE	326
	Exelon Corporation	326
	Exelon Generation Company, LLC	326
	Commonwealth Edison Company	327
	PECO Energy Company	328
ITEM 11.	EXECUTIVE COMPENSATION	329
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	373
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	376
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	376
	Exelon Corporation	376
	Exelon Generation Company, LLC	377
	Commonwealth Edison Company	377
	PECO Energy Company	377

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		Page No.
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	379
SIGNATURES		397
	Exelon Corporation	397
	Exelon Generation Company, LLC	398
	Commonwealth Edison Company	399
	PECO Energy Company	400
CERTIFICATION EXHIBITS		401

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FILING FORMAT

This combined Form 10-K is being filed separately by Exelon Corporation (Exelon), Exelon Generation Company, LLC (Generation), Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) (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 factors with respect to such registrant 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: Note 18 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 at www.sec.gov and Exelon’s website at www.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 at www.exeloncorp.com and will be made available, without charge, in print to any shareholder who requests such documents from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

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PART I

ITEM 1. BUSINESS

General

Exelon, a utility services holding company, operates through its principal subsidiaries—Generation, ComEd and PECO—as described below, each of which is treated as an operating segment by Exelon. See Note 20 of the Combined 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.

Generation

Generation’s business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and its competitive retail sales operations.

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 businesses at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-5959.

ComEd

ComEd’s energy delivery business consists of the purchase and regulated retail and wholesale sale of electricity and the provision of 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 retail sale of electricity and the provision of distribution and transmission services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of 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.

Termination of 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), a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG would have been

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merged with and into Exelon (Merger). On September 14, 2006, Exelon terminated the Merger Agreement as a result of the failure to receive timely approval of the Merger from the New Jersey Board of Public Utilities (NJBPU).

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 Illinois Commerce Commission (ICC). PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the Pennsylvania Public Utility Commission (PAPUC). Generation, ComEd and PECO are electric utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). Specific operations of the Registrants are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the Nuclear Regulatory Commission (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 (Energy Policy Act). With the repeal of PUHCA, the restrictions are no longer applicable to Exelon, and the SEC’s financing jurisdiction under PUHCA for Generation’s financings and ComEd’s and PECO’s short-term financings transferred to FERC. Exelon’s financings are not subject to FERC jurisdiction.

Under the Energy Policy Act, FERC was granted additional jurisdiction for review of mergers, 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.

Generation

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

At December 31, 2006, Generation owned generation assets with an aggregate net capacity of 25,543 MWs, including 16,945 MWs of nuclear capacity. In addition, Generation controlled another 7,691 MWs of capacity through long-term contracts.

Generation’s wholesale marketing unit, Power Team, a major wholesale marketer of energy, draws upon Generation’s energy generation portfolio and logistical expertise to ensure delivery of energy to Generation’s wholesale customers under long-term and short-term contracts, including a power purchase agreement (PPA) with PECO and, beginning in 2007, ICC-approved standardized supplier forward contracts with ComEd and Ameren Corporation (Ameren). In addition, Power Team markets energy in the wholesale bilateral and spot markets.

Generation’s retail business provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Michigan and Ohio. Generation’s retail 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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The PPA between Generation and PECO expires at the end of 2010. Generation's PPA with ComEd expired at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren auctions in Illinois for the procurement of electricity. As a result of the expiration of the PPA with ComEd and the results of the auctions, beginning in 2007, Generation will sell more power through bilateral agreements with other new and existing counterparties. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

Generating Resources

At December 31, 2006, the generating resources of Generation consisted of the following:

Type of Capacity	MWs
Owned generation assets (a)
Nuclear	16,945
Fossil	6,992
Hydroelectric	1,606
Owned generation assets	25,543
Long-term contracts (b)	7,691
TEG and TEP (c)	230
Total generating resources	33,464

(a) See “Fuel” for sources of fuels used in electric generation.

(b) Long-term contracts range in duration up to 25 years.

(c) At December 31, 2006, Generation, through its investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), owned 49.5% interests in two facilities in Mexico, each with a capacity of 230 MWs. On February 9, 2007, Generation sold its ownership interests in TEG and TEP.

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) of the United States. The generating capacity that Generation controls through long-term contracts is in the Midwest, Southeast and South Central regions.

Nuclear Facilities

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with 16,945 MWs of capacity. Generation’s nuclear fleet plus its ownership interest in the Salem Generating Station (Salem), operated by PSEG Nuclear, LLC (PSEG Nuclear), generated 139,610 GWhs, or approximately 92% of Generation’s total output, for the year ended December 31, 2006. For additional information regarding Generation’s electric generating capacity by station, see ITEM 2. Properties. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, an indirect, wholly owned subsidiary of PSEG. AmerGen Energy Company, LLC (AmerGen), wholly owned subsidiary of Generation, operates the Clinton Nuclear Power Station (Clinton), the Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek).

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 stations, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the stations. The initial two-year term of the OSC terminated

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on January 16, 2007. However, PSEG Nuclear has exercised its right to require Generation to continue services under the OSC for an additional two-year termination transition period. Under the OSC, PSEG Nuclear has a right to extend the termination transition period for an additional year and PSEG Nuclear has reserved its right to do so.

In 2006 and 2005, electric supply generated from the nuclear generating facilities was 73% and 71%, respectively, of Generation’s total electric supply which also includes MWs purchased for resale and fossil and hydroelectric generation. During 2006 and 2005, the nuclear generating facilities operated by Generation achieved a 93.9% and 93.5% capacity factor, respectively.

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 the 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, 2006, indicate that the performance indicators for the nuclear plants operated by Generation are all in the highest performance band, with the exception of one indicator for Dresden Unit 2, and one indicator for Byron Unit 2, both of which are still considered to be in an acceptable performance band within that indicator by the NRC.

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 Generation’s application for renewal. The application for Oyster Creek’s license renewal was filed July 22, 2005, in compliance with this order. Generation expects to apply for and obtain approval of license renewals for the remaining facilities. 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.

In 2004, Generation joined NuStart Energy Development, LLC (NuStart), a consortium of eleven companies that 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, 2006, Generation’s investment in NuStart was $1 million.

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

(a) Stations previously owned by ComEd.

(b) Stations previously owned by PECO.

(c) Stations owned by AmerGen.

(d) NRC license renewals have been received for these units.

(e) 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, 2006, Generation had approximately 46,778 SNF assemblies (11,317 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)
Braidwood	2013
Byron	2011
Clinton (b)	2006
Dresden	Dry cask storage in operation
LaSalle	2012
Limerick	2009
Oyster Creek	Dry cask storage in operation
Peach Bottom	Dry cask storage in operation
Quad Cities	Dry cask storage in operation
Salem	2011
Three Mile Island	Life of plant storage capable in SNF pool

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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 receive a full complement of fuel from the reactor core.

(b) Clinton has currently lost full core discharge capability. A modification to the on-site storage pool is in progress to increase the amount of SNF that can be stored in the pool and is expected to be completed in late 2007. 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 kilowatthour (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 has published a schedule for opening a SNF permanent disposal facility and its current estimate is 2017. 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. Generation plans to submit annual reimbursement requests to the DOE 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. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding spent fuel storage claims and issues.

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 defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2006, the unfunded liability for the one-time fee with interest (which has been assumed by Generation) was $950 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, 2006, was 5.108%. 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.

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 an 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

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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. Generation paid $32 million in 2006 ($28 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, 2006, 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 each nuclear operator 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 18 of the Combined 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 specified minimum amounts at the end of the life of the facility to decommission the facility. As more fully described below, ComEd collected amounts from customers through 2006 for facilities formerly owned by ComEd, and PECO is currently collecting amounts from customers for facilities formerly owned by PECO, which are ultimately remitted to the trust funds maintained by Generation that will be used to decommission those nuclear facilities. AmerGen also maintains decommissioning trust funds for each of its plants in accordance with NRC regulations. The AmerGen units, specifically Clinton, Oyster Creek, and TMI, are not covered by any rate recovery process for customer funding of decommissioning costs. Decommissioning expenditures are expected to occur primarily after the plants are retired. Certain decommissioning costs are currently being incurred; however, these current amounts are not considered material compared to the total ARO.

Under an ICC order, ComEd was permitted to recover up to $73 million per year through 2006 from customers to decommission former ComEd nuclear plants. Collections were limited based on the ratio of electricity purchased by ComEd to the total amount generated from those units. In 2006, decommissioning revenues collected from ComEd customers totaled approximately $66 million. 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 or partly owned by PECO continue to be 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 amounts recovered are premised on studies that assume level contributions through the license expiration date for each unit. After completion of the decommissioning, any excess amounts in the decommissioning trusts for the nuclear generating stations formerly owned by ComEd and PECO that were collected from customers must be returned to ComEd and PECO customers, respectively.

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Generation believes that the decommissioning trust funds for the nuclear generating stations formerly owned by ComEd and PECO, the expected earnings thereon and, in the case of PECO, the amounts currently being collected from PECO’s customers will be sufficient to fully fund Generation’s decommissioning obligations for the nuclear generating stations formerly owned by ComEd and PECO. Generation further believes the AmerGen nuclear decommissioning 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 and Note 13 of the Combined Notes to Consolidated Financial Statements for a further discussion of nuclear decommissioning.

Zion, a two-unit nuclear generation station, Peach Bottom Unit 1 and Dresden Unit 1 have 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. The present value of Generation’s liability to decommission Zion, Peach Bottom Unit 1 and Dresden Unit 1 was $795 million at December 31, 2006. As of December 31, 2006, nuclear decommissioning trust funds set aside to pay for this obligation were $1.2 billion.

Fossil and Hydroelectric Facilities

Generation operates various fossil and hydroelectric facilities and maintains ownership interests in several other facilities such as LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2006 and 2005, approximately 8% 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 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. For those plants located within PJM Interconnection, LLC (PJM) or the New England control area administered by ISO New England Inc. (ISO-NE), notice is required before a plant can be retired.

Insurance. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. Generation maintains both property damage and liability insurance. For property damage and liability claims, 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. For information regarding property insurance, see ITEM 2. Properties—Generation.

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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	2008 to 2023	1,997
Total			7,691

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

Federal Power Act

The Federal Power Act gives 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 FERC’s jurisdiction are required to file rate schedules with FERC with respect to wholesale sales and transmission of electricity. Open-Access 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 FERC’s acceptance of the rate schedules for wholesale sales of electricity. In 2000, Generation received authorization from FERC to sell power at market-based rates. As is customary with market-based rate schedules, FERC reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determined that Generation or any of its affiliates violated the terms and conditions of its tariff or the Federal Power Act. 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.

In 2004, FERC implemented new market power tests for suppliers to qualify to sell power at market-based rates. These tests consist of the market share test and the pivotal supplier test, both of which must 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. FERC allows the relevant geographic market to include a regional transmission organization’s (RTOs) footprint, and Generation used an expanded PJM footprint as the relevant market.

On July 5, 2005, 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, FERC required Generation to address the affiliate abuse and reciprocal dealing prong of FERC’s market-based rate eligibility test, instituting a proceeding under Section 206 of the Federal Power Act, and pending a compliance filing by Generation. On April 3, 2006, FERC accepted Exelon’s compliance filings regarding its triennial update of market-based rates and terminated proceedings under Section 206 of the Federal Power Act. For further discussion of this matter, see Note 4 of the Combined Notes to Consolidated Financial Statements.

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For a number of years, 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 regional planning, managing transmission congestion, developing larger wholesale markets for energy and capacity, maintaining reliability, market monitoring and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems. See Transmission Services below for a further discussion.

To date, PJM, the Midwest Independent System Operator, Inc. (MISO), ISO-NE and Southwest Power Pool, have been approved as RTOs. Because of some states’ opposition to imposition of centralized energy and capacity markets, FERC is seeking to obtain some of the benefits of RTOs by means of making more effective rules governing open-access transmission in regions that do not have RTOs or independent system operators.

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 various transmission providers.

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 the transmission infrastructure, 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 transferred to FERC certain additional authority. FERC was granted 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. Additionally, 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. On July 20, 2006, pursuant to the Energy Policy Act, FERC certified the North American Electric Reliability Corporation (NERC) as the nation’s Electric Reliability Organization. As a result, owners and operators of the bulk power transmission system, including Generation, ComEd and PECO, will be subject to mandatory reliability standards promulgated by NERC and enforced by FERC.

See Note 4 of the Combined Notes to Consolidated Financial Statements for further information on the Energy Policy Act of 2005 and its impact on the Registrants.

Market-Based Rates Matters

Currently, Exelon’s entities have been approved by FERC to sell power at market-based rates. On May 19, 2006, FERC issued a Notice of Proposed Rule Making (NOPR) on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, which would modify the tests that Exelon and other market participants must satisfy to be entitled to sell at market-based rates. Exelon currently expects that FERC will rule on the NOPR in the first or second quarter of 2007 and Exelon is not certain as to the impact of any new rules that are promulgated as a result of FERC’s future ruling with respect to the NOPR. Also, triggered by the expiration of the full-requirements PPA between Generation and ComEd and the resulting increase in Generation’s uncommitted capacity, on December 15, 2006, Exelon made a Change in Status (CIS) filing with

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FERC. Exelon’s filing, supported by an updated market-power analysis, demonstrated that Exelon continues to be entitled to market-based rates. The time period for interventions expired on January 5, 2007, no party intervened, and on February 9, 2007, FERC accepted Exelon’s CIS filing. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information on Market-Based Rates Matters and its impact on the Registrants.

PJM Reliability Pricing Model (RPM)

On August 31, 2005, PJM filed its RPM with FERC to replace its current capacity market rules. The RPM proposal provided for a forward capacity auction using a demand curve and locational deliverability zones for capacity phased in over a several year period beginning on June 1, 2006. On November 5, 2005, PJM proposed to delay the effective date of the RPM until June 1, 2007. On April 20, 2006, FERC issued an order generally finding aspects of PJM’s RPM filing to be just and reasonable, but FERC also established further procedures to resolve the remaining issues and encouraged the parties to seek a negotiated resolution. A final settlement was filed with FERC on September 29, 2006 and FERC issued its order approving the settlement, subject to conditions, on December 22, 2006. FERC’s adoption of the settlement proposal of September 2006 is expected to have a favorable impact for owners of generation facilities, and particularly for such facilities located in constrained zones. The final revenue impact of the settlement on Generation, particularly over an extended time period, however cannot be estimated at this time.

FERC has also denied requests for rehearing of its April 20, 2006 order. The time for filing a petition for review of FERC’s April 2006 order will expire on February 20, 2007. In addition, FERC’s order approving the settlement subject to conditions is subject to requests for rehearing and judicial review. PJM will almost certainly implement RPM in 2007 notwithstanding, as FERC’s orders are rarely stayed, and therefore almost always remain in effect, pending appellate review. The first auction, which is scheduled to occur in April 2007, will allow Generation to better estimate the revenue impact for the period June 1, 2007 through May 31, 2008.

Fuel

The following table shows sources of electric supply in gigawatthours (GWhs) for 2006 and estimated for 2007:

	Source of Electric Supply
	2006	2007 (Est.)
Nuclear units (a)	139,610	139,752
Purchases—non-trading portfolio	38,297	29,766
Fossil and hydroelectric units	12,773	15,285
Total supply	190,680	184,803

(a) Represents Generation's proportionate share of the output of its nuclear generating plants, including Salem, which is operated by PSEG Nuclear.

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 obligations to ComEd and PECO, some of Generation’s retail business 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

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requirements through 2009. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2010. 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 to meet the nuclear fuel requirements of its nuclear units.

Generation obtains approximately 30% 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 natural 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. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information regarding derivative financial instruments.

Power Team

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long-term, intermediate-term and short-term contracts. Generation seeks to maintain a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. PPAs 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 electricity markets. 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 economically hedged is approximately three years. Generation has estimated a greater than 90% economic and cash flow hedge ratio for

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2007 for its energy marketing portfolio. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to ComEd and PECO. A portion of Generation’s hedge may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. 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. 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. 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.

At December 31, 2006, 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)
2007	$	468	$	5,401	$	1,499	$	6
2008		425		1,900		475		—
2009		398		647		194		—
2010		417		100		194		—
2011		417		—		106		—
Thereafter		2,960		—		249		—
Total	$	5,085	$	8,048	$	2,717	$	6

(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, 2006. Expected payments include certain capacity charges which are conditional on plant availability.

(b) Transmission rights purchases include estimated commitments in 2007 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 agreed to supply all of ComEd’s load requirements through 2006. Under the ComEd PPA, prices for energy varied depending upon the time of day and month of delivery. Beginning January 2007, ComEd is procuring all of its supply from market sources pursuant to the ICC-approved procurement auction, which includes 35% from Generation. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail on the impact of ComEd’s procurement process on Generation. Generation has a PPA with PECO under which Generation has agreed to supply PECO with substantially all of PECO’s electric supply needs through 2010. Generation supplies electricity to PECO from its portfolio of generation assets, 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 2007 are as follows:

(in millions)
Production plant	$	754
Nuclear fuel		599
Total	$	1,353

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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 and regulated retail and wholesale sale of electricity and the provision of distribution and transmission services 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 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 3.8 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. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to residential, commercial and industrial customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services 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 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 1.6 million customers and natural gas to approximately 480,000 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 “grandfathered 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 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 1, 2006 and was 23,613 MWs; its highest peak load during a winter season occurred on February 5, 2007 and was 16,207 MWs. PECO’s highest peak load occurred on August 3, 2006 and was 8,932 MWs; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MWs.

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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).

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 competitive electric generation suppliers for the supply of retail electricity while transmission and distribution service remains regulated. The legislation and related regulatory orders in both states allowed customers to choose a competitive electric generation supplier; required rate reductions and imposed freezes or caps on rates during a transition period following the adoption of the legislation; and allowed 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 a competitive electric generation supplier or who choose to return to the utility after taking service from a competitive electric generation supplier. These requirements are referred to as provider of last resort (POLR) obligations.

ComEd. As more fully described below, ComEd’s transition period has ended and new unbundled rates for service became effective January 2007. All of ComEd’s customers are eligible to choose a competitive electric generation supplier, and most non-residential customers also have a power purchase option (PPO) that is based on market-based rates. As of December 31, 2006, one competitive electric generation supplier had been granted approval by the ICC to serve residential customers in Illinois; however, it is not currently supplying electricity to any of ComEd’s residential customers. All of ComEd’s customers are eligible to choose a competitive electric generation supplier or may purchase electricity from ComEd at rates, including the PPO option, that are based on a reverse-auction process. At December 31, 2006, approximately 20,300 non-residential customers, representing approximately 28% of ComEd’s annual retail kWh sales, had elected to purchase their electricity from a competitive electric generation supplier or had chosen the PPO. Customers who receive electricity from a competitive electric generation supplier and customers who have elected the PPO continue to pay a delivery charge to ComEd.

Illinois Procurement Case and Initial ComEd Auction. On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of electricity by ComEd after the end of the transition period. This approval, currently under appeal before the Illinois Appellate Court, 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 through a transparent market mechanism. The first procurement auction for ComEd’s entire load took place during September 2006, for electricity to be delivered beginning in January 2007. Auction participants bid on several different products including 17-, 29- and 41-month contracts that will be “blended” together and used to serve residential and small commercial customers, a 17-month “annual” product that will be used to serve larger non-residential customers, and a variably priced “hourly” product that would be used to serve customers who either select hourly service or are not eligible to receive fixed price service. The ICC accepted the auction results related to the blended and annual products but rejected the auction results for the hourly product. Under ComEd’s tariffs, electricity that would have been procured through the hourly auction is currently being purchased in the PJM-administered wholesale electricity markets. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

Rate Freeze Extension Proposal. In 2006 and 2007, various bills, amendments and “compromise” legislation were separately passed by the Illinois House and the Illinois Senate in a legislative session

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that ended on January 9, 2007, including, in the Illinois House, an extension of the Illinois transition period rate freeze with a rollback of rates to 2006 levels. However in order to take effect, any legislation would need to be passed by both the Illinois House and Illinois Senate and be signed by the Governor of Illinois. The legislative session ended on January 9, 2007 without any legislation having passed both the Illinois House and the Illinois Senate. All legislation pending at the close of the legislative session on January 9, 2007 expired. A new session is underway and legislation similar to previously proposed legislation has been reintroduced. ComEd is unable to predict the final disposition of any legislation that may be presented during 2007 to rollback rates, change the end of the mandated transition and rate freeze period in Illinois, or otherwise. ComEd believes a rate rollback and freeze, if enacted into law, would have serious detrimental effects on Illinois, ComEd and consumers of electricity. ComEd believes such legislation, if enacted into law, will violate Federal law and the U.S. Constitution, and ComEd is prepared to vigorously challenge any such legislation in court. If legislation similar to the “compromise” bill previously passed by the Illinois Senate to phase-in the rate increases is enacted, there would be material adverse effects on Exelon’s and ComEd’s results of operations and cash flows as the “compromise” bill did not provide for the recovery of carrying charges. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

Illinois Rate Case. On August 31, 2005, ComEd filed a rate case with the ICC to comprehensively review its tariff and to adjust ComEd’s rates for delivering electricity effective January 2007 (Rate Case). On July 26, 2006, the ICC issued its order in the Rate Case which approved a delivery services revenue increase of approximately $8 million of the $317 million proposed revenue increase requested by ComEd. The ICC subsequently granted in part requests for rehearing of ComEd and various other parties. On December 20, 2006, the ICC issued an order on rehearing that increased the amount previously approved by approximately $74 million, including a partial return on the pension asset, for a total rate increase of $83 million. ComEd and various other parties have appealed the rate order to the courts. It is unlikely the appeal will be resolved until the second half of 2007 at the earliest. In the event the order is ultimately changed, the changes should be prospective only. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

Residential Rate Stabilization Program. To mitigate the impact on its residential customers of ComEd’s transition to a reverse-auction competitive bidding process for the procurement of electricity, the ICC approved a program, proposed by ComEd, which offers residential customers the choice to elect to defer electric rate increases greater than 10% in each of the years from 2007 to 2009. ComEd will recover the deferred balances over three years from 2010 to 2012. Deferred balances will be assessed an annual carrying charge of 3.25%. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

Original Cost Audit. In the Rate Case, the ICC, ordered an “original cost” audit of ComEd’s distribution assets. The original cost audit report is expected to be finalized in 2007 with an ICC proceeding to follow the issuance of the report. This proceeding may extend into 2008. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

Other. Illinois law 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. Recovery of consequential damages is barred and the affected utility may 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 2006, 2005 and 2004, ComEd did not have any outages that triggered the reimbursement requirement.

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, 2006, less than 1% of each of PECO’s residential and large commercial

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and industrial loads and 10% of its small commercial and industrial load were purchasing generation service from competitive electric generation suppliers. Customers who purchase electricity from a competitive electric generation supplier continue to pay a delivery charge to PECO.

In addition to retail competition for generation services, PECO’s 1998 settlement of its restructuring case mandated by the Competition Act established caps on generation, transmission 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 2006, the generation rate cap was $0.0751 per kWh, increasing to $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 between 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. PECO’s capped transmission and distribution rates continue in effect until PECO files a rate case or there is some other specific regulatory action to adjust the rates. There are no current proceedings to do so.

As a mechanism for utilities to recover 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 a competitive electric generation supplier. The Competition Act provides, however, that the utility’s right to collect transition charges is contingent on the continued operation, at reasonable availability levels, of the assets for which the stranded costs were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.

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, 2006, the unamortized balance of PECO’s stranded costs, or CTC regulatory asset, was $3.0 billion. The following table shows PECO’s allowed recovery of stranded costs, and amortization of the associated regulatory asset, for the years 2007 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 charge rates 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
2007	$	910	$	619
2008		917		697
2009		924		783
2010		932		883

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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 and Generation 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 FERC. FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. Under FERC’s open access transmission policy promulgated in Order No. 888, 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 FERC’s Order No. 889, ComEd and PECO are required to comply with 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.

PJM is the independent system operator and the FERC-approved RTO for the Mid-Atlantic and Midwest regions. 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 through central dispatch, controls the day-to-day operations of the bulk power system for 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.

In November 2004, 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 territories of PJM or MISO. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), were collected from load-serving entities and paid to transmission owners within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

On May 31, 2005, FERC issued an order creating an evidentiary hearing process to examine the existing PJM transmission rate design. An administrative law judge (ALJ) order related to this process was issued on July 13, 2006, which, if adopted by FERC, would result in a change to the existing rate design. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

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

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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 distribution base rates for recovery of costs other than purchased gas costs will continue in effect until PECO files a rate case or there is some other specific regulatory action to adjust the rates.

PECO’s gas customers have the right to choose their gas suppliers or to purchase their gas supply from PECO at cost. Approximately 35% 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 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 three years. These purchases are delivered under long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 42 million dekatherms. Peak gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 22 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 33% of PECO’s 2006-2007 heating season planned supplies.

Construction Budget

ComEd’s and PECO’s businesses are capital intensive and require significant investments primarily in energy transmission and distribution facilities. The following table shows the most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2007:

(in millions)	ComEd		PECO
Electric	$	1,055	$	269
Gas		—		65
Common		—		21
Total	$	1,055	$	355

Approximately 50% of the projected 2007 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.

Employees

As of December 31, 2006, Exelon and its subsidiaries had approximately 17,200 employees in the following companies:

Generation	7,700
ComEd	5,500
PECO	2,100
Other (a)	1,900
Total	17,200

(a) Other includes shared services employees at Exelon Business Services Company (BSC).

Approximately 5,500 employees, including 3,800 employees of ComEd, 1,600 employees of Generation and 100 employees of BSC, are covered by collective bargaining agreements (CBAs) with

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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. In addition, a separate CBA between ComEd and IBEW Local 15, which was ratified on November 7, 2006, covers approximately 140 employees in ComEd's System Services Group and expires on October 1, 2009. 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 Local 369, covering approximately 40 employees, which was ratified effective January 31, 2007 and which continues from year to year unless either party expresses its intention to terminate the agreement. In addition, Exelon Power has an agreement with IBEW Local 614, which expires on January 31, 2008 and covers approximately 200 employees.

During 2004, two elections were held at PECO, which resulted in union representation for PECO craft and call center employees in the Philadelphia service territory. PECO and IBEW Local 614 began negotiations for initial agreements in 2005. Although substantial progress has been made, no agreements have been finalized to date. The negotiations continue with the possibility of a tentative agreement being reached by the end of the first quarter in 2007. The current affected workgroup totals approximately 1,200 employees.

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. After contesting the election, the National Labor Relations Board ruled that a new election must be conducted. This election took place on November 16, 2006. The employees again voted against union representation.

Environmental Regulation

General

Exelon, Generation, ComEd and PECO 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. Various state environmental protection agencies or boards have jurisdiction over certain activities in states in which Exelon and its subsidiaries do business. 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. The Clean Water Act requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. The Phase II rule establishes national performance standards for reducing entrainment and impingement of aquatic organisms at existing power plants. On January 25, 2007, the U.S. Second Circuit Court of Appeals issued its opinion in a challenge to the final Phase II rule brought by environmental groups and several states. The court found that with respect to a number of significant provisions of the rule the EPA either

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exceeded its authority under the Clean Water Act, failed to adequately set forth its rationale for the rule, or failed to follow required procedures for public notice and comment. The court remanded the rule back to the EPA for revisions consistent with the court’s opinion. The court’s opinion has created significant uncertainty about the specific nature, scope and timing of the final compliance requirements. See Note 18 of the Combined Notes to Consolidated Financial Statements for detail on the impact of this rule to Generation.

On December 16, 2005 and February 27, 2006, the Illinois EPA issued violation notices to Generation alleging violations of state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station. On March 16, 2006, the Attorney General of the State of Illinois, and the State’s Attorney for Will County, Illinois filed a civil enforcement action, seeking, among other things, injunctive relief to require certain remedial actions for past tritium releases, and to prevent future releases. In addition, a class action lawsuit and several individual lawsuits were filed on behalf of persons living within the vicinity of the Braidwood Nuclear Generating Station. As of December 31, 2006 and 2005, Generation had a reserve of $3 million and $7 million (pre-tax), respectively, for this matter, which Generation deems adequate to cover the costs of remediation and potential related corrective measures.

Generation launched an initiative across its 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. On September 28, 2006, Generation announced the final results of the assessment, concluding that no active leaks had been identified at any of Generation’s 11 nuclear plants and no detectable tritium had been identified beyond any of the plants’ boundaries other than from permitted discharges, with the exception of Braidwood, as discussed above. The assessment further concluded that none of the tritium concentrations identified in the assessment pose a health or safety threat to the public or to Generation’s employees or contractors. See Note 18 of the Combined Notes to Consolidated Financial Statements for further detail.

Generation is also subject to the jurisdiction of certain other state and regional 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.

Generation, ComEd and PECO 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

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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.

MGP Sites

MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to the 1950s. 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. ComEd and PECO have identified former MGP sites for which they may be liable for remediation. See Note 18 of the Combined Notes to Consolidated Financial Statements for further detail.

Cotter Corporation

The EPA has advised Cotter Corporation, 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. See Note 18 of the Combined Notes to Consolidated Financial Statements for further detail.

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), mercury 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 (SO₂ 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 Acid Rain Program Phase II SO₂ and NO_x limits of the Amendments, which became effective January 1, 2000. Generation and the other Keystone co-owners formally approved on June 30, 2006 a capital plan to install SO₂ scrubbers at the station for which Exelon’s share, based on its 20.99% ownership interest, would be approximately $150 million. In addition, Generation and the other Keystone co-owners purchase SO₂ emission allowances as part of their compliance strategy to meet 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 and the coal-fired unit at Cromby (Selective Non-Catalytic Reduction) and installed controls on the two coal-fired units at the

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Keystone Generating Station (Selective Catalytic Reduction). Generation’s NO_x compliance program is supplemented with the purchase of additional NO_x allowances on an as-needed basis. The eight 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 annual (applicable in 23 eastern states) and ozone season (applicable in 25 eastern states) NO_x emission 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 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 agreed to reconsider and take additional public comment regarding certain aspects of its final CAIR and CAMR rulemakings. In March 2006, EPA determined that it would uphold its final CAIR rulemaking without change. In May 2006, EPA determined that, except for a number of minor technical revisions, it would maintain the CAMR as previously finalized.

During 2006, Pennsylvania proposed a state-level mercury regulation that is more stringent than the Federal CAMR. This rulemaking was finalized in October 2006 and submitted to the EPA in November 2006. Under the first phase of the regulation, starting in 2010, pulverized coal units will be required to meet either an emission rate of 0.024 lb mercury/GWh or an 80% mercury capture efficiency and comply with a unit-level annual mercury emissions limit that must be met by surrendering non-tradable mercury allowances. Under the second phase of the proposed regulation, starting in 2015, units will be required to meet either a 0.012 lb/GWh emission rate or 90% capture efficiency and a reduced annual emissions limit. While the PDEP rulemaking does not allow for mercury emission allowance trading for compliance, it does allow for emission limit compliance on a facility or system-wide (under common ownership) basis.

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.

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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. At a regional level, 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. The RGGI Memorandum of Understanding (MOU) is an agreement to stabilize aggregate carbon dioxide emissions from power plants in participating states at current levels from 2009 to 2015. Further, reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant emissions. As of December 31, 2006, states participating in the RGGI MOU include Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont. Maryland, which had been an observer to the process, has also committed to join RGGI based on state legislation passed in 2006. On August 15, 2006, the RGGI model rule was finalized. RGGI member states will now be required to adopt state-level legislation and/or regulation to implement the program starting in 2009. Massachusetts has also recently joined RGGI as a result of legislation passed effective January 18, 2007. Further, the RGGI states will continue to work on some as yet unresolved issues, such as how to address emissions leakage due to power flows from non-RGGI states into RGGI states. Generation owns a small amount of affected 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.

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 CO₂ emission intensity, or rate of CO₂ emitted per kilowatt-hour of electricity generated, is among the lowest in the industry.

Exelon announced on May 6, 2005 that it has established a voluntary goal to reduce its greenhouse gas (GHG) emissions by 8% from 2001 levels by the end of 2008. The 8% 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.

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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 required. 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 purchases of Tier I and Tier II sources by electric distribution companies prior to the expiration of their specific cost recovery periods is also allowed under the AEPS Act. Voluntary purchases 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 the automatic energy adjustment clause as a cost of generation supply.

During 2006, the PAPUC issued additional implementation orders and proposed regulations related to compliance schedules, banking of alternative energy credits, compliance, cost recovery, force majeure, alternative compliance payments and voluntary alternative energy purchases. It is anticipated that, during 2007, the PAPUC will finalize regulations concerning AEPS implementation issues.

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 and, at the same time, may present some opportunities for sales of renewable power.

The ICC, in a January 24, 2006 order, ordered its staff to initiate three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources. On October 12, 2006, the ICC voted 5 to 0 to dismiss the three rulemaking proceedings. Separately on April 4, 2006, ComEd filed with the ICC a request for ICC approval to purchase and receive recovery of costs associated with the output of a portfolio of competitively procured wind resources of approximately 300 MW. ComEd asked, and the ALJ agreed, to continue these proceedings until

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February 2007. In the ICC’s December 20, 2006 order approving ComEd’s residential rate stabilization program, the ICC also strongly encouraged, but did not require, ComEd to make contributions totaling $30 million to environmental and customer assistance programs. ComEd is currently evaluating this request. See Note 4 of the Combined Notes to Consolidated Financial Statements for further detail.

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, 2006, Exelon, Generation, ComEd and PECO had accrued $119 million, $20 million, $58 million and $41 million, respectively, for various environmental investigation and remediation. Exelon, ComEd and PECO have recorded regulatory assets of $73 million, $47 million and $26 million, respectively, related to the recovery of MGP remediation costs. See Notes 18 and 19 of the Combined Notes to Consolidated Financial Statements for further detail.

The amounts to be expended in 2007 at Exelon, Generation, ComEd and PECO for compliance with environmental requirements total approximately $41 million, $17 million, $15 million and $9 million, respectively. In addition, Generation, ComEd and PECO may be required to make significant additional expenditures not presently determinable.

Managing the Risks in the Business

Exelon, Generation, ComEd and PECO 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.

Generation

Costs to meet contractual commitments. 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 aggressively manage its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s short and long-term supply commitments and Power Team trading activities.

Operating services arrangement. Effective in 2005, as a result of the OSC with PSEG Nuclear, Generation is providing services to oversee daily plant operations at the Salem and Hope Creek nuclear generating stations. Under the OSC, PSEG Nuclear remains as the license holder with exclusive legal authority to operate and maintain the stations, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. As a result of the OSC, Generation has decreased certain exposures and increased revenues from its share of Salem, which it co-owns with PSEG Nuclear. The initial two-year term of the OSC

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terminated on January 16, 2007. However, PSEG Nuclear has exercised its right to require Generation to continue services under the OSC for an additional two-year termination transition period. Under the OSC, PSEG Nuclear has a right to extend the termination transition period for an additional year and PSEG Nuclear has reserved its right to do so.

Adequacy of funds to decommission nuclear power plants. Generation has an obligation to decommission its nuclear power plants. The ICC permitted ComEd through 2006, and the PAPUC permits PECO to collect funds, from their customers, which are deposited in nuclear decommissioning trust funds maintained by Generation. The collections by 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 both 2006 and 2005. Because ComEd did not take all of the output of these stations, actual collections were $66 million and $68 million in 2006 and 2005, respectively. PECO is currently recovering $33 million annually for nuclear decommissioning. It is anticipated that these collections will continue through the operating license life of each of the former PECO units, with adjustments every five years, subject to certain limitations, 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. Certain decommissioning costs are currently being incurred; however these current amounts are not considered material compared to the total ARO. Generation develops its decommissioning trust fund investment strategy based on an estimate of the timing and costs associated with nuclear decommissioning. To the extent that actual decommissioning activities result in higher costs or are incurred in the nearer term, Generation may not have sufficient funds to pay for decommissioning. To fund future decommissioning costs, Generation held $6.4 billion of investments in trust funds at December 31, 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for further detail.

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 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. Generation’s sales to counterparties other than ComEd and PECO will increase due to the expiration of the PPA with ComEd at the end of 2006. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. Under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, beginning in 2007, collateral postings between ComEd and Generation and between Ameren and Generation will be one-sided. That is, if market prices fall below ComEd’s or Ameren’s contracted price levels, ComEd or Ameren are not required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation is required to post collateral.

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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. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity trading portfolio. Generation enters into derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2007 and 2008. However, Generation is exposed to relatively greater commodity price risk in the subsequent years for which a larger portion of its electricity portfolio may be unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years as well. Generation has estimated a greater than 90% economic and cash flow hedge ratio for 2007 for its energy marketing portfolio.

The PPA between Generation and PECO expires at the end of 2010. Market prices for electricity have generally increased significantly over the past few years due to the rise in natural gas and fuel prices. As a result, PECO customers’ generation rates are below current wholesale energy market prices, and Generation’s margins on sales in excess of ComEd’s and PECO’s requirements have improved due to its significant capacity of low-cost nuclear generating facilities. Generation’s ability to maintain those margins will depend on future fossil fuel prices and its ability to obtain high capacity factors at its nuclear plants.

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.

ComEd and PECO

Post-transition rates. In 2006, ComEd received orders from the ICC in several regulatory proceedings to establish the rates to be charged to customers effective January 2007. The first order relates to ComEd’s ability to procure electricity supply. The second order and the associated order on rehearing established the delivery service rates that will be charged to customers. Appeals are pending related to each order. A third order allows ComEd’s residential customers to have the choice to elect to defer any electric rate increases over 10% in each of the years 2007 to 2009. Any deferred balances will accrue interest and, in general, will be collected in 2010 to 2012 with a carrying charge of 3.25% per year beginning at the time of deferral.

While PECO has made no regulatory filings to date to revise its transmission and distribution rates established in 2000, 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 retail generation rates are adequate to cover its costs of obtaining electricity from its suppliers, which could include Generation.

Mandatory RPS. ComEd expects to recover from customers any increased costs associated with RPS legislation if enacted. PECO is responsible for meeting its RPS requirements and, in that regard, plans to file with the PAPUC in the first quarter of 2007 a proposal to purchase renewable energy credits commencing as early as 2008. PECO expects to recover from customers all costs associated with RPSs. The Registrants are currently evaluating the potential impacts of RPS legislation on their businesses.

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Power supply risks. To effectively manage its obligation to provide power to meet its customers’ demand, ComEd has supplier forward contracts, effective January 2007, with various energy providers as a result of its reverse-auction competitive bidding process. ComEd is allowed by the ICC to recover from customers the cost of purchased electricity. Therefore, should an approved supplier default and ComEd be required to purchase replacement electricity, ComEd would be entitled to recover any incremental costs from customers. To effectively manage its obligation to provide power to meet its customers’ demand, PECO has a full-requirements PPA with Generation which reduces PECO’s exposure to the volatility of customer demand and market prices through 2010.

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 and economic operation of both systems.

General Business

Security risk. The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, 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 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 in 2007 in the event the tax credits are completely phased out. Additionally, under current laws, the tax credits related to the production of synthetic fuel expire on December 31, 2007. See Note 12 of the Combined Notes to Consolidated Financial Statements for further detail.

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

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Executive Officers of the Registrants

Exelon

Name	Age	Position
Rowe, John W.	61	Chairman, Chief Executive Officer and President
Clark, Frank M.	61	Chairman and Chief Executive Officer, ComEd
McLean, Ian P.	57	Executive Vice President and President, Power Team
Mehrberg, Randall E.	51	Executive Vice President, Chief Administrative Officer and Chief Legal Officer
Moler, Elizabeth A.	58	Executive Vice President, Governmental and Environmental Affairs and Public Policy
Skolds, John L.	56	Executive Vice President, Exelon, President, Exelon Energy Delivery and President, Exelon Generation
Snodgrass, S. Gary	55	Executive Vice President and Chief Human Resources Officer
Young, John F.	50	Executive Vice President, Finance and Markets and Chief Financial Officer
Hilzinger, Matthew F.	43	Senior Vice President and Corporate Controller

Generation

Name	Age	Position
Rowe, John W.	61	Chairman, Chief Executive Officer and President, Exelon
Young, John F.	50	Executive Vice President, Finance and Markets and Chief
		Financial Officer, Exelon, and Chief Financial Officer
Skolds, John L.	56	Executive Vice President, Exelon, and President
McLean, Ian P.	57	Executive Vice President, Exelon, and President, Power Team
Crane, Christopher M.	48	Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear
Schiavoni, Mark A.	51	Senior Vice President and President, Exelon Power
Veurink, Jon D.	42	Vice President and Controller

ComEd

Name	Age	Position
Clark, Frank M.	61	Chairman and Chief Executive Officer
Mitchell, J. Barry	59	President
Costello, John T.	58	Executive Vice President and Chief Operating Officer
McDonald, Robert K.	51	Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer
Pramaggiore, Anne R.	48	Senior Vice President, Regulatory and External Affairs
Hooker, John T.	58	Senior Vice President, Legislative and Governmental Affairs
Galvanoni, Matthew R.	34	Vice President and Controller

PECO

Name	Age	Position
Rowe, John W.	61	Chairman, Chief Executive Officer and President, Exelon, and Director
Young, John F.	50	Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer
Skolds, John L.	56	Executive Vice President, Exelon, President, Exelon Energy Delivery, and Director
O’Brien, Denis P.	46	President and Director
Crutchfield, Lisa	43	Senior Vice President, Regulatory and External Affairs
Galvanoni, Matthew R.	34	Vice President and Controller

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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 positions, Mr. Clark was Executive 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 and Chief Executive Officer of ComEd effective November 28, 2005. Mr. Clark is listed as an executive officer of Exelon by reason of his position as the Chairman and Chief Executive Officer of ComEd.

Prior to his election to his listed position, Mr. McLean was Senior Vice President of Exelon; and President of the Power Team division of PECO. 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. 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; and Director of Unicom and ComEd. 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. 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.

Prior to his election to his listed position, Mr. Hilzinger was Executive Vice President and Chief Financial Officer of Credit Acceptance Corporation; and Vice President, Controller of Kmart Corporation. Mr. Hilzinger was elected as an officer of Exelon effective April 15, 2002. Mr. Hilzinger was Principal Accounting Officer for ComEd and PECO through December 31, 2006.

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.

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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.

Prior to his election to his listed position, Mr. Mitchell was Senior Vice President, Chief Financial Officer and Treasurer of Exelon, Generation, ComEd and PECO; 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 was Senior Vice President of Exelon Energy Delivery Technical Services. Mr. Costello was 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 was 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 was 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 positions, Mr. Galvanoni was Director of Financial Reporting and Analysis, Exelon. Mr. Galvanoni has also served as Director of Accounting and Reporting, Generation; Director of Reporting, Exelon; and was a senior manager at PricewaterhouseCoopers LLP. Mr. Galvanoni was elected to his listed positions effective January 1, 2007.

Prior to her election to her listed position, Ms. Crutchfield served as Vice President, Regulatory and External Affairs, PECO; and Vice President and General Manager at Southern Service Center. Ms. Crutchfield was elected to her listed position effective January 1, 2007.

ITEM 1A. RISK FACTORS

The Registrants each operate in a market and regulatory environment that involves significant risks, many of which are beyond their control. The Registrants’ management regularly evaluates the most significant risks of the Registrants’ businesses and discusses those risks with the Risk Oversight Committee of the Exelon Board of Directors and the ComEd Board of Directors. The following items identify the material risks that the Registrants’ management discussed in December 2006.

• The safe and efficient operation of Generation’s nuclear fleet is a significant factor in Exelon’s results of operations. Although Generation’s nuclear plants are among the most efficient in the United States, there is a risk that Generation’s nuclear capacity factors could be significantly lower than planned or operating or fuel costs could be significantly higher than expected.

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• After 2006 in Illinois, Generation has been selling, and after 2010 in Pennsylvania, Generation will be selling more of its electricity through bilateral agreements with new and existing counterparties at prices susceptible to market fluctuations. As a result, over time Exelon will shift from a company with relatively stable cash flows from its regulated affiliates to a company with cash flows that could vary significantly with changes in market prices for electricity and natural gas.

• Prior to 2007, Generation supplied electricity to ComEd at prices that were below market prices. Generation supplies electricity to PECO at prices that are currently below prevailing market prices under a PPA that expires at the end of 2010. ComEd’s customers are experiencing increases in their costs for electric service beginning in 2007, and PECO’s customers could expect to see increases in their electric bills after 2010. In Illinois, Pennsylvania and other states, there is growing pressure on state regulators and governments to take steps to reduce the impact of price increases on retail customers. A move away from fully competitive generation markets as a result of regulatory or statutory requirements could significantly affect Exelon’s and Generation’s results of operations.

• ComEd’s and PECO’s business plans are based on the assumption that the utilities will receive fair regulatory treatment and therefore, based on current Federal and state regulatory structures, can recover from customers revenue sufficient to cover their costs and earn a fair return. ComEd and PECO face the risk that rates for electric service will be set at levels that do not cover their costs of the purchase and distribution of electricity plus a fair return on their investments in transmission and distribution systems.

• Generation attempts to reduce its exposure to energy market price fluctuations through derivative transactions. Hedging increases liquidity requirements due to margining requirements. Generation’s current PPA with PECO does not include a margin requirement. Beginning in 2007, Generation’s forward supply contracts with ComEd and third parties in Illinois do include margin requirements. Beginning in 2011, Generation’s contracts for supply of electricity to PECO may also include margin requirements. Generation will need to maintain expanded credit facilities to meet these margin requirements.

• Exelon and Generation maintain and manage trust funds to meet future employee pension, postretirement and nuclear decommissioning costs. The fund investments are market instruments that will yield uncertain returns. There is a risk that the fund investments may not achieve projected returns, which could adversely affect Exelon’s and Generation’s results of operations and cash flows.

• Active employee and retiree health care and pension cost are a significant part of Exelon’s cost structure. The costs associated with health care or pension obligations could escalate at rates higher than anticipated, which would adversely affect Exelon’s results of operations and cash flows.

• The nature of the Registrants’ businesses has the potential to have significant effects on the general public due to severe weather, environmental or nuclear incidents, gas explosions, or prolonged electricity outages. The financial impact of an incident that interrupts the normal operation of a Registrant’s business for an extended period of time could be significant.

• Exelon is subject to extensive environmental regulation and associated compliance costs. Regulations under section 316(b) of the Federal Clean Water Act require actions to address the entrainment and impingement of aquatic organisms in the cooling water intakes of electric generation facilities. A number of Generation’s facilities will be affected by these regulations, which could impose significant compliance costs on Generation for required modifications of its facilities.

The risks listed above are discussed in further detail below, along with other risk factors identified by the Registrants. These risk factors, as well as the risks discussed in ITEM 7. Management’s

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Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Liquidity and Capital Resources, may adversely affect the Registrants’ results of operations and cash flows and the market prices of their publicly traded securities. While each of the Registrants believes it has identified and discussed 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.

Generation

Market Transition Risks

Due to its dependence on two of its significant customers, ComEd and PECO, Generation will be negatively affected in the event of non-performance or change in the creditworthiness of either of its most significant customers.

Generation currently provides power under a PPA with PECO and supplier forward contracts with ComEd to meet 100% of PECO’s electricity supply requirements and up to 35% of ComEd’s electricity supply requirements. Consequently, Generation is highly dependent on ComEd’s and PECO’s continued payments under these supplier forward contracts and the PPA and would be adversely affected by negative events affecting these agreements, including the non-performance or a change in the creditworthiness of either ComEd or PECO. A default by ComEd or PECO under these agreements would have an adverse effect on Generation’s results of operations and financial position.

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. 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. Generation’s future results of operations, however, will depend on (1) FERC’s continued adherence to and support for policies that favor the development of competitive wholesale power markets, such as the PJM market and (2) with respect to PJM, the absence of material changes to market structure that limit or otherwise negatively affect the competitiveness of the market.

Provider of Last Resort. PECO and ComEd have POLR obligations to meet their respective retail customers’ energy supply needs. To enable it to fulfill that obligation through the end of 2010, PECO has a full-requirements PPA with Generation. To fulfill its obligation for energy supply beginning in 2007, ComEd has and will in the future conduct procurement auctions. In the first ICC-approved procurement auction, 14 wholesale suppliers, including Generation, won the right to provide to ComEd the energy supply it needs to serve its retail customers from January 1, 2007 through May 31, 2008. Generation’s share of this supply is 35%.

Because retail customers in both Pennsylvania and Illinois can switch from PECO or ComEd to a competitive electric generation supplier for their energy needs, planning to meet PECO’s obligation to supply PECO with all of the energy PECO needs to fulfill its POLR obligation and to provide the supply needed to serve Generation’s 35% share of the ComEd load is more difficult than planning for retail load before the advent of retail competition. Before retail competition, the primary variables affecting

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projections of load were weather and the economy. With retail competition, another major factor is the ability of retail customers to switch to competitive electric generation suppliers. If fewer of such customers switch than Generation anticipates, the PECO and/or ComEd load that Generation must serve will be greater than anticipated, which could, if market prices have increased, increase Generation’s costs (due to its need to go to market to cover its incremental supply obligation) more than the increase in Generation’s revenues. If more of such customers switch than Generation anticipates, the PECO and /or ComEd load that Generation must serve will be lower than anticipated, which could, if market prices have decreased, caused Generation to lose opportunities in the market.

Generation may not be able to effectively respond to competition in the energy industry.

Generation’s financial performance depends in part on its ability to respond to competition in the energy industry. As a result of industry restructuring, numerous generation companies created by the disaggregation of vertically integrated utilities have become active in the wholesale power generation business. In addition, independent power producers 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 lower prices and have an adverse effect on Generation’s results of operations or financial condition.

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

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

Nuclear refueling outages. 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 capacity factor between 0.3% and 0.5%. The number of refueling outages, including the AmerGen plants and the co-owned plants, was 11 in 2006 with 9 planned for 2007. The projected total non-fuel capital expenditures for the nuclear plants operated by Generation will increase

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in 2007 compared to 2006 by approximately $37 million as Generation continues to invest in equipment upgrades to ensure safe reliable operations. Total operating and maintenance expenditures are expected to increase by approximately $52 million in 2007 compared to 2006 as a result of inflationary cost increases.

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. 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 to reimburse Generation for these costs. Also, any regulatory action relating to the availability of a repository for spent nuclear fuel may adversely affect Generation’s ability to fully decommission the nuclear units. In addition, through the NRC’s “waste confidence” rule, 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 basin or at either onsite or offsite independent spent fuel storage installations.

License renewals. Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of any renewed license. If the NRC does not renew the operating licenses for Generation’s nuclear stations or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs.

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.

Environmental risk. If application of the Section 316(b) regulations establishing a national requirement for reducing the adverse impacts from the entrainment and impingement of aquatic organisms at existing generating stations requires the retrofitting of cooling water intake structures at Oyster Creek, Salem or other Exelon power plants, 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

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may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners.

Nuclear accident risk. Although the safety record of nuclear reactors, 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. 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 for a single incident.

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 portion of the NEIL distribution for 2006 was $44 million, which was recorded as a reduction to operating and maintenance expenses in its Consolidated Statement of Operations. Generation cannot predict the level of future distributions or if they will continue at all.

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. 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, 2006, Generation identified trust funds for 6 units, which, at current market levels, are being funded at a rate less than anticipated with respect to NRC Funding Levels. In December 2006, Generation made a submission to the NRC addressing this issue, demonstrating in accordance with NRC requirements, that the trust funds for these 6 units indeed met NRC Funding Levels and remain adequately funded compared to the NRC Funding Level, when using alternate evaluation criteria allowed by NRC regulations. The NRC Funding Levels are based upon the assumption that decommissioning will commence at the end of current licensed life.

Forecasting investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from current estimates. Ultimately, 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.

A significant portion of Generation’s portfolio is used to provide power under a long-term PPA with PECO and supplier forward contracts with ComEd beginning January 2007, as a result of the expiration of the PPA between Generation and ComEd at the end of 2006. To the extent portions of the

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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 under the related agreements, 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.

FERC has required electric transmission services to be offered unbundled from commodity sales since 1996. Although this encourages wholesale market transactions for electricity, access to transmission systems may 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. The expansion of PJM and the growth of other RTOs mitigate this risk to a degree as RTOs facilitate bilateral transactional activity in the physical wholesale markets wholly within those RTOs without any need to secure transmission service.

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-term 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 that is not used to meet its long-term supply commitments, including 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.

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 likely reflects 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

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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.

Generation’s credit risk profile is anticipated to change based on the creditworthiness of new and existing counterparties, including ComEd and Ameren. Additionally, due to the possibility of rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to the risk of default and, in the event of a bankruptcy filing by ComEd or Ameren, a risk that the bankruptcy may result in rejection of contracts for the purchase of electricity. A default by ComEd or Ameren on contracts for purchase of electricity, or a rejection of those contracts in a bankruptcy proceeding, could result in a disruption in the wholesale power markets. For additional information on the ComEd auction and the various regulatory proceedings and possible legislative actions, see Note 4 of the Combined Notes to Consolidated Financial Statements.

In addition, the retail businesses 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 Generation 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 have a material adverse effect upon its liquidity. If Generation had lost its investment grade credit rating as of December 31, 2006, it would have been required to provide approximately $880 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. Problems in or the failure of any of these markets, as was experienced in California in 2000, could adversely affect Generation’s business.

Hedging. 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 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. Extreme 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.

Generation’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 this 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

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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.

Generation’s financial performance may be negatively affected by price volatility, availability and other risk factors associated with the procurement of fossil and nuclear fuel.

Generation depends on coal, natural gas and nuclear fuel assemblies to operate its generating facilities. Coal is procured for coal-fired plants through annual, short-term and spot-market purchases. Natural gas is procured through annual, monthly and spot-market purchases. Nuclear fuel assemblies are obtained through long-term uranium concentrate inventory and supply contracts, contracted conversion services, contracted enrichment services and fuel fabrication services. The supply markets for coal, natural gas and nuclear fuel assemblies are subject to price fluctuations and availability restrictions that may negatively affect the results of operations for Generation. It is not possible to predict the ultimate cost or availability of these commodities. Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate price risk associated with these commodity price exposures.

ComEd and PECO

The following risk factors separately apply to each ComEd and PECO as further noted below.

Regulatory Risks

Changes in ComEd’s and PECO’s terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which lead to uncertainty as to the ultimate result and which may introduce time delays in effectuating rate changes.

ComEd and PECO are required to engage 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 timelines, which may not be limited by statute. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. For example, in ComEd’s most recent rate cases in Illinois, the ICC took eleven months to issue its orders which were followed by rehearing proceedings and numerous appeals.

In certain instances, ComEd and PECO may agree to negotiated settlements related to various rate matters and customer initiatives. These settlements are typically subject to regulatory approval.

ComEd and PECO cannot predict the ultimate outcomes of any settlements or the actions by the Illinois and Pennsylvania state regulators for establishing rates. Nevertheless, the expectation is that

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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.

The ultimate outcome of these regulatory actions 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. Additionally, lengthy proceedings and time delays in implementing new rates relative to when costs are actually incurred could have a material adverse effect on ComEd’s and PECO’s results of operations and cash flows.

ComEd’s and PECO’s established rates are subject to subsequent prudency reviews by the state regulators.

The ICC and PAPUC can adjust various portions of ComEd’s and PECO’s, respectively, established rates, including rates for the procurement of electricity and the recovery of MGP remediation costs, in the regulatory process as a result of subsequent prudency reviews. The prudency reviews add uncertainty to established rates.

Increases in customer rates may lead to a greater amount of uncollectible customer balances for ComEd and PECO. Future recoverability of any additional uncollectible customer balances is subject to regulatory proceedings.

Effective January 2007, ComEd’s customer rates for delivery service and procurement of electricity increased. Additionally, ComEd’s residential customers have the choice to elect to defer certain increases to future periods. See Note 4 of the Combined Notes to the Consolidated Financial Statements for more information. PECO’s gas rates may change quarterly based on market conditions which may lead to higher prices. Additionally, PECO’s electric rates have increased in recent years as permitted under the Electric Restructuring Settlement and the PECO/Unicom Merger Settlement Agreements. Due to increased rates and the future collection of deferred balances, ComEd and PECO may experience a greater amount of uncollectible customer balances.

ComEd may file for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code if rate rollback and freeze legislation is enacted into law.

In January 2007, ComEd began billing customers under new rates approved by the ICC. These rates reflect the pricing in supplier forward contracts entered into as a result of a reverse-auction competitive bidding process for ComEd’s procurement of electricity. Various governmental and consumer groups have opposed the increased rates that are a byproduct of this auction, and legislation previously proposed in the Illinois House that, if enacted, would provide for a rate rollback and three-year rate freeze extension. If such legislation is enacted into law, ComEd would have contractual obligations to purchase electricity under the supplier forward contracts at prices higher than the rates it would be allowed to collect from its customers for electricity. ComEd has estimated that it could incur operating losses of approximately $1.4 billion per year ($850 million after taxes) or more, depending on various factors, if rates were rolled back and the transition period rate freeze is extended through 2009. Also, ComEd’s ability to obtain new financing or the ability to refinance maturing debt instruments in 2007, would be severely limited due to expected shortfalls in cash flow, likely further credit downgrades to below investment grade and the threat of a bankruptcy filing. ComEd’s projected cash shortfall under a rate freeze extension is anticipated to be approximately $1.4 billion or more in 2007. If rate rollback and rate freeze legislation is passed and allowed to take effect, the associated negative financial implications could lead ComEd to file for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code.

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The impact of not meeting the criteria of Financial Accounting Standards Board Statement No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) could be material to ComEd and PECO.

As of December 31, 2006, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria of SFAS No. 71. 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 and the recognition of a one-time extraordinary item in their Consolidated Statements of Operations and Comprehensive Income (Loss). The impact of not meeting the criteria of SFAS No. 71 could be material to the financial statements of Exelon, ComEd and PECO. At December 31, 2006, the income statement gain could have been as much as $2.3 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2006, the income statement charge could have been as much as $3.7 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. Exelon would record an income statement gain or charge in an equal amount related to ComEd’s and PECO’s regulatory assets and liabilities in addition to a charge against other comprehensive income of up to $1.4 billion (before taxes) related to Exelon’s regulatory assets associated with its defined benefit postretirement plans. The impacts and resolution of the above items could lead to an additional impairment of ComEd’s goodwill, which would be significant and at least partially offset the extraordinary gain discussed above. A write-off of regulatory assets and liabilities also could limit the ability of ComEd and PECO to pay dividends under Federal and state law. See Notes 1, 4, 8 and 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory issues, ComEd’s goodwill and regulatory assets and liabilities, respectively.

Mandatory RPS could negatively affect ComEd’s and PECO’s costs.

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 renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. ComEd and PECO continue to monitor developments related to RPSs at the Federal and state levels.

For additional information, see ITEM 1. Business “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards”.

ComEd and PECO could be subject to higher transmission operating costs in the future as a result of PJM’s regional transmission expansion plan (RTEP).

On November 7, 2006, FERC established hearing procedures to review the cost allocations proposed by PJM for a number of PJM mandated RTEP projects that will be placed into service over the next three years. ComEd and PECO did not challenge PJM’s allocations of cost to them but, due to the uncertain scope of the matter and the nature of certain allocation issues specifically reserved for hearing, the matter may have an adverse impact on ComEd’s and PECO’s operating costs in the future.

PECO may be subject to the risk of a legislative or regulatorily mandated requirement to purchase Philadelphia Gas Works (PGW).

PGW is a municipal gas utility owned by the City of Philadelphia that provides service almost exclusively within Philadelphia. One Pennsylvania state legislator recently submitted legislation to the

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Pennsylvania General Assembly that would provide the PAPUC with the authority to investigate PGW’s fitness to provide gas service and, if deemed unfit, to require a qualified public utility to purchase PGW’s gas assets. If such legislation is enacted, PECO, with a gas service territory contiguous to, and an electric service territory that includes Philadelphia, could be subject to a proceeding in which efforts are made to require PECO to purchase PGW’s gas assets. While PECO believes that such a forced purchase would be unlawful, such a proceeding could expose PECO potentially to significant economic risk.

PECO may be required to change various business processes as a result of PAPUC management audit findings.

Under Pennsylvania law, a public utility is subject to a broad management and operations audit conducted by the PAPUC or a consultant hired by the PAPUC every five to eight years. PECO is currently undergoing such an audit by a consultant hired by the PAPUC. Areas of the audit include, among others, electric and gas operations, corporate governance, customer service, and affiliate relations. A final audit report is expected to be issued by the PAPUC in the third quarter of 2007. The audit could result in recommendations that PECO change various business processes to improve its effectiveness in providing electric and gas service to its customers.

Financial and Operating Risks

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 FERC requiring ComEd and PECO to upgrade or expand their respective transmission systems through additional capital expenditures.

ComEd’s and PECO’s operating costs, and customers’ and regulators’ opinions of ComEd and PECO, 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 transmission and 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.

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, are designed for PECO to recover the cost of the gas commodity and pipeline transportation and storage services that PECO procures to service its customers. PECO’s cash flows can be impacted by differences between the time period when gas is purchased and the ultimate recovery from customers.

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When purchased gas cost charges increase substantially reflecting 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 customer balances.

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 normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. 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 each company’s 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 they are unable to effectively manage their own respective capital projects or if they do not receive full recovery of their own respective capital costs through future regulatory proceedings.

Other

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

Exelon and ComEd had approximately $2.7 billion of goodwill recorded at December 31, 2006 in connection with the PECO/Unicom merger. Under accounting principles generally accepted in the United States (GAAP), 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 impairments recorded during 2006 and 2005, the amount of the impaired goodwill will be written off and expensed, reducing equity.

There is a possibility that additional goodwill may be impaired at ComEd, and at Exelon, in 2007 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. Such a potential impairment charge could have a material impact on Exelon’s and ComEd’s operating results.

See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Critical Accounting Policies and Estimates for further discussion on goodwill impairments.

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General Business

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

Exelon’s generation and energy delivery businesses may be negatively affected by possible state legislative or regulatory actions that could limit the retail price of electricity or place burdens on its generation business.

Criticism of restructured electricity markets in public forums escalated during 2006 as retail rate freezes expired in a number of states as fuel prices increased, thereby driving up retail prices for electricity. ComEd’s customers are experiencing increases in their costs for electric service beginning in 2007, and PECO’s customers could expect to see increases in their electric bills after 2010. Consumers in other states are also experiencing significant rate increases. In Illinois, Pennsylvania and other states, there is growing pressure for state regulatory and political processes to take steps to reduce the impact of price increases on retail customers. The political pressure for states to retreat from allowing competitively-priced supplies to serve retail load and to return to cost-based regulation of generation resources or take other actions directed at generators of electricity creates heightened risk of limitations on the retail price of electricity, which could significantly affect the results of operations of ComEd and PECO, and a heightened risk of imposition of restrictions and other burdens on Exelon’s generation business, which could significantly affect Generation’s results of operations.

Generation may be negatively affected by possible Federal legislative or regulatory actions that could weaken competition in the wholesale markets or affect pricing rules in the RTO markets.

The criticism of restructured electricity markets, which escalated during 2006 as retail rate freezes expired and prices for electricity increased with rising fuel prices, is expected to continue in 2007. A number of advocacy groups have urged FERC to reconsider its support for competitive wholesale electricity markets, and to require the RTOs to revise the rules governing the RTO-administered markets. In particular, the advocacy groups oppose the RTOs’ use of a “single clearing price” for electricity sold in the RTO markets. FERC has announced that it will convene a series of public conferences during 2007 to address the issues surrounding electric competition. While FERC has not proposed to revise its pricing rules, these events create heightened risk of changes in FERC’s rules governing wholesale electricity markets, which in turn could significantly affect Generation’s results of operations.

In addition, FERC has proposed to revise the tests that market participants must satisfy to be entitled to market-based rates. The actual impacts of any new rules that are approved as a result of FERC’s future ruling related to market-based rates could significantly affect Generation’s results of operations.

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 regulatory recovery process for ComEd and PECO, rate caps for PECO and price pressures due to competition, ComEd and PECO may not be able to recover the costs of inflation from their customers on a timely basis.

In addition, the Registrants face rising medical benefit costs, including the current costs for active and retired employees. These medical benefit costs are increasing at a rate that is significantly greater than the rate of general inflation. Additionally, it is possible that these costs may increase at a rate which is higher than anticipated by the Registrants. If the Registrants are unable to successfully manage their medical benefit costs or other increasing costs, their results of operations could be negatively affected.

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Market performance and other changes 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. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below the Registrants’ projected return rates. A decline in the market value of the assets, as was experienced from 2000 to 2002, may increase the funding requirements of these obligations. Additionally, changes in interest rates affect the liabilities under Exelon’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension benefit plans. If the Registrants are unable to successfully manage the decommissioning trust funds and benefit plan assets, their results of operation and financial position could be negatively affected.

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 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, Generation, ComEd and PECO 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 2006, ComEd did not pay any dividend.

Exelon and Generation will be negatively affected if ComEd files for voluntary relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code.

There is a risk that ComEd will be required to seek protection in bankruptcy if legislation is enacted in Illinois to extend the rate freeze that expired in January 2007. Exelon anticipates that a bankruptcy filing by ComEd would have significant adverse consequences for Exelon and Generation. These adverse consequences may include, but are not limited to: a significant loss in value of Exelon’s investment in ComEd; possible dilution of Exelon’s ownership interest in ComEd; possible reductions in credit ratings which could increase borrowing costs; uncertainty in collection of receivables from ComEd for services provided by BSC; uncertainty in the enforcement of Generation’s rights under its supplier forward contracts with ComEd and possible rejection of the supplier forward contracts in a ComEd bankruptcy; significant legal and other costs associated with the bankruptcy filing; possible negative income tax consequences; and possible reduced ability to effectively administer and allocate the costs of the various Exelon-sponsored benefit plans. These items, along with other possible negative effects of a ComEd bankruptcy, could have a material adverse effect on Exelon’s and Generation’s results of operations, financial position and cash flows.

The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards.

As a result of the Energy Policy Act, owners and operators of the bulk power transmission system, including Generation, ComEd and PECO, will be subject to mandatory reliability standards promulgated by NERC and enforced by FERC. These standards are currently being applied on a

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voluntary basis and are expected to become mandatory in June 2007. The standards are based on the functions that need to be performed to ensure the bulk electric system operates reliably and is guided by reliability and market interface principles. Compliance with new reliability standards may subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC and PAPUC impose certain distribution reliability standards on ComEd and PECO. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to sanctions, including substantial monetary penalties.

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. Violations of these emission and disposal requirements can subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages. 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.

Generation will incur material costs of compliance if regulations under Section 316(b) of the Clean Water Act require retrofitting of cooling water intake structures at power plants owned by Generation. 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 could require Generation to contribute to a fund with a material contribution to settle lawsuits for alleged asbestos-related disease and exposure.

In some cases, a third party who has acquired assets from a Registrant has assumed the liability the Registrant may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability, a regulatory authority or injured person could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee may be limited by the financial resources of the transferee.

Select northeast and mid-Atlantic states have developed a model rule, via the RGGI, to regulate carbon emissions from fossil-fired generation in participating states starting in 2009. Federal and/or state legislation to regulate carbon emissions could occur in the future. If these plans become effective, Exelon and Generation may incur costs to either further limit the emissions from certain of their fossil-fuel fired facilities or in procuring emission allowance credits issued by various governing bodies.

For additional information regarding environmental matters, including nuclear generating station groundwater, 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

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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, Afghanistan 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 disasters in its service territory and throughout the U.S. Severe weather or other natural disasters could be destructive which could result in increased costs including supply chain costs.

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 property damage and liability insurance, together with the deductible, could negatively affect the Registrants’ 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 that may be subject to challenge by the Internal Revenue Service (IRS), such as Exelon’s decision to defer the tax gain on ComEd’s 1999 sale of its fossil generating assets. 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, and tax credits, including the potential phase-out of tax credits for the sale of synthetic fuel produced from coal, 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 Notes 1 and 12 of the Combined Notes to Consolidated Financial Statements for further detail.

Increases in state income taxes and fees. 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.

In connection with the first reverse-auction competitive bidding process, which took place in Illinois during September 2006, Exelon assessed any impacts from the results of the auction on its state

49

income tax obligations and considered potential strategies and/or alternative interpretations that may be employed to mitigate these impacts. As a result, Exelon does not believe the results of the auction will significantly affect the provision for state income taxes reported by Exelon on an annual basis. However, management’s estimates of future income tax rates are affected by various factors and actual income tax obligations may differ from management’s estimates. See Note 4 of the Combined Notes to Consolidated Financial Statements for information regarding the reverse-auction competitive bidding process.

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. 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 sale leaseback transaction into which ComEd entered in connection with the fossil plant sale is proper pursuant to applicable law. The Federal tax returns and related tax return disclosures covering the period of the 1999 sale are currently under IRS audit. The IRS has indicated its position that the ComEd sale leaseback transaction is substantially similar to a leasing transaction, a sale-in, lease-out (SILO), the IRS is treating as a “listed transaction” pursuant to guidance it issued in 2005. A listed transaction is one that the IRS considers to be a potentially abusive tax shelter. As a result of the IRS characterization of the lease transaction as a listed transaction, the IRS is likely to vigorously challenge the transaction and has sought to obtain information not normally requested in audits. Exelon disagrees with the IRS’ characterization of its sale leaseback as a SILO and believes its position is correct under the tax law and will aggressively defend that position upon audit and any subsequent appeals or litigation.

In November 2006, ComEd received from the IRS a notice of proposed adjustment disallowing the deferral of gain associated with its position that proceeds from the fossil plant sales resulted from an “involuntary conversion.” ComEd plans to protest this adjustment following receipt of the final IRS audit report, which is expected in late 2007.

A successful IRS challenge to ComEd’s positions would accelerate future income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of December 31, 2006, Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $960 million. If the deferral were successfully challenged by the IRS, it could negatively affect Exelon’s results of operations by as much as $166 million (after tax) related to interest expense. See Note 12 of the Combined 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. However, 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. At December 31, 2006, Exelon has estimated the 2007 phase-out of tax credits to be 18%. This estimate for 2007 may change significantly due to the volatility of oil 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. See Note 12 of the Combined Notes to Consolidated Financial Statements, the Executive Overview and Liquidity and Capital Resources in ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation for further detail.

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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 18 of the Combined 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 FERC or the state public utility commissions may impose certain other restrictions on the investments that the Registrants may make. Achieving the anticipated benefits of an investment is subject to a number of uncertainties, and failure to achieve these anticipated benefits 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Exelon, Generation, ComEd and PECO

None.

ITEM 2. PROPERTIES

Generation

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2006. 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	1,048
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	1,303	(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
						16,945

(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	Intermediate	147
Cromby 2	Phoenixville, PA	1		Oil/Gas	Intermediate	211
Eddystone 1, 2	Eddystone, PA	2		Coal	Intermediate	599
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	357	(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	355
Schuylkill	Philadelphia, PA	1		Oil	Peaking	175
Wyman	Yarmouth, ME	1	5.89	Oil	Intermediate	36	(d)
						5,191
Fossil (Combustion Turbines)
Chester	Chester, PA	3		Oil	Peaking	54
Croydon	Bristol Twp., PA	8		Oil	Peaking	497
Delaware	Philadelphia, PA	4		Oil	Peaking	74
Eddystone	Eddystone, PA	4		Oil	Peaking	76
Falls	Falls Twp., PA	3		Oil	Peaking	60
Framingham	Framingham, MA	3		Oil	Peaking	41
LaPorte	Laporte, TX	4		Gas	Peaking	160
Medway	West Medway, MA	3		Oil/Gas	Peaking	172
Moser	Lower Pottsgrove Twp., PA	3		Oil	Peaking	60
New Boston	South Boston, MA	1		Oil	Peaking	18
Pennsbury	Falls Twp., PA	2		Landfill Gas	Peaking	6
Richmond	Philadelphia, PA	2		Oil	Peaking	132
Salem	Hancock’s Bridge, NJ	1	42.59	Oil	Peaking	16	(d)
Schuylkill	Philadelphia, PA	2		Oil	Peaking	38
Southeast Chicago	Chicago, IL	8		Gas	Peaking	312
Southwark	Philadelphia, PA	4		Oil	Peaking	72
						1,788
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	1,070
						1,606
Total		126				25,543

(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 daytime higher load hours, and consequently, produce electricity by cycling on and off daily. Peaking units consist of low-efficiency, quick response steam units, gas turbines, diesels and pumped-storage hydroelectric equipment normally used during the maximum load periods.

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.

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, 2006 were as follows:

	Voltage (Volts)	Circuit Miles
ComEd	765,000	90
	345,000	2,621
	138,000	2,867
	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 interest in 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500,000 voltage lines located in Delaware and New Jersey.

ComEd’s electric distribution system includes 43,197 circuit miles of overhead lines and 34,917 cable miles of underground lines. PECO’s electric distribution system includes 12,811 circuit miles of overhead lines and 15,224 cable miles of underground lines.

Gas

The following table sets forth PECO’s gas pipeline miles at December 31, 2006:

	Pipeline Miles
Transmission	31
Distribution	6,623
Service piping	5,398
Total	12,052

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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.

ITEM 3. LEGAL PROCEEDINGS

Exelon, Generation, ComEd and PECO

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Notes 4 and 18 of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

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

Exelon, Generation, ComEd and PECO

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, 2007, there were 670,157,335 shares of common stock outstanding and approximately 154,087 record holders of common stock.

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

	2006								2005
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	63.62	$	61.98	$	58.86	$	59.90	$	56.00	$	57.46	$	52.01	$	47.18
Low price		57.83		56.74		51.13		52.79		46.62		49.60		44.14		41.77
Close		61.89		60.54		56.83		52.90		53.14		53.44		51.33		45.89
Dividends		0.400		0.400		0.400		0.400		0.400		0.400		0.400		0.400

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 during the fourth quarter of 2006.

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, 2006	10,460	$	60.55	—	(b	)
November 1—November 30, 2006	—		59.28	2,223,250	(b	)
Total	10,460		59.29	2,223,250	(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.

(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.

Generation

As of January 31, 2007, Exelon held the entire membership interest in Generation.

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ComEd

As of January 31, 2007, 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, 2007, in addition to Exelon, there were 269 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

PECO

As of January 31, 2007, there were outstanding 170,478,507 shares of common stock, without par value, of PECO, all of which were held by Exelon.

Exelon, Generation, ComEd and PECO

Dividends

Under applicable Federal law, Generation, ComEd and PECO can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd or PECO 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. ComEd may not declare any 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 issued to ComEd Financing II or ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing II or ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

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, 2006, 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 PECO Energy Capital, L.P. (PEC L.P.) or PECO Energy Capital Trust IV (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, 2006, Exelon had retained earnings of $3.4 billion, which includes Generation’s undistributed earnings of $1.8 billion, ComEd’s retained deficit of $(193) million consisting of an unappropriated retained deficit of $(1.6) billion, partially offset by $1.4 billion of retained earnings appropriated for future dividends and PECO’s retained earnings of $584 million.

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2006 and 2005:

	2006								2005
(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	$	0.400	$	0.400	$	0.400

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

	2006								2005
(in millions)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter
Generation	$	165	$	122	$	157	$	165	$	108	$	430	$	80	$	239
ComEd		—		—		—		—		146		107		107		138
PECO		134		117		135		116		122		116		116		115

On December 5, 2006, the Exelon Board of Directors declared a regular quarterly dividend of $0.44 per share on Exelon’s common stock. The dividend is payable on March 10, 2007, to shareholders of record of Exelon at 5:00 p.m. Eastern Standard Time on February 15, 2007. This dividend declaration was made by the Exelon Board of Directors in connection with the Board of Director’s approval of a value return policy that established a base dividend that Exelon expects will grow modestly over time. The value return policy contemplates the use of share repurchases from time to time, when authorized by the Board of Directors, to return cash or balance sheet capacity to Exelon shareholders after funding maintenance capital and other commitments and in the absence of higher value-added growth opportunities. Previously, Exelon had maintained a dividend payout policy of between 50-60% of ongoing operating earnings.

During 2006, ComEd did not pay a quarterly dividend. This decision by the ComEd Board of Directors not to declare a dividend was the result of several factors, including ComEd’s need for a rate increase to cover existing costs and anticipated levels of future capital expenditures as well as the continued uncertainty related to ComEd’s regulatory filings as discussed in Note 4 of the Combined Notes to Consolidated Financial Statements. ComEd’s Board of Directors will continue to assess ComEd’s ability to pay a dividend on a quarterly basis.

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	2006		2005			2004			2003			2002
Statement of Operations data:
Operating revenues	$	15,655	$	15,357		$	14,133		$	15,148		$	14,060
Operating income		3,521		2,724			3,499			2,409			3,280
Income from continuing operations	$	1,590	$	951		$	1,870		$	892		$	1,690
Income (loss) from discontinued operations		2		14			(29	)		(99	)		(20	)
Income before cumulative effect of changes in accounting principles		1,592		965			1,841			793			1,670
Cumulative effect of changes in accounting principles (net of income taxes)		—		(42	)		23			112			(230	)
Net income (a), (b)	$	1,592	$	923		$	1,864		$	905		$	1,440
Earnings per average common share (diluted):
Income from continuing operations	$	2.35	$	1.40		$	2.79		$	1.36		$	2.60
Income (loss) from discontinued operations		—		0.02			(0.04	)		(0.15	)		(0.03	)
Cumulative effect of changes in accounting principles (net of income taxes)		—		(0.06	)		0.03			0.17			(0.35	)
Net income	$	2.35	$	1.36		$	2.78		$	1.38		$	2.22
Dividends per common share	$	1.60	$	1.60		$	1.26		$	0.96		$	0.88
Average shares of common stock outstanding—diluted		676		676			669			657			649

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.

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

	December 31,
in millions	2006		2005		2004		2003		2002
Balance Sheet data:
Current assets	$	4,992	$	4,637	$	3,880	$	4,524	$	4,096
Property, plant and equipment, net		22,775		21,981		21,482		20,630		17,957
Noncurrent regulatory assets		5,808		4,734		5,076		5,564		6,061
Goodwill (a)		2,694		3,475		4,705		4,719		4,992
Other deferred debits and other assets		8,050		7,970		7,867		6,800		5,249
Total assets	$	44,319	$	42,797	$	43,010	$	42,237	$	38,355
Current liabilities	$	5,795	$	6,563	$	4,836	$	5,683	$	5,845
Long-term debt, including long-term debt to financing trusts (c)		11,911		11,760		12,148		13,489		13,127
Noncurrent regulatory liabilities		2,975		2,518		2,490		2,229		1,001
Other deferred credits and other liabilities (b)		13,578		12,743		13,918		12,246		9,968
Minority interest		—		1		42		—		77
Preferred securities of subsidiaries (c)		87		87		87		87		595
Shareholders’ equity		9,973		9,125		9,489		8,503		7,742
Total liabilities and shareholders’ equity	$	44,319	$	42,797	$	43,010	$	42,237	$	38,355

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the goodwill impairment charge of $776 million and $1.2 billion in 2006 and 2005, respectively.

(b) Change between 2006 and 2005 was primarily due to the impact of adopting SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158).

(c) Due to the adoption 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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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 Generation’s retail business are not included in periods prior to 2004.

	For the Years Ended December 31,
(in millions)	2006		2005			2004			2003			2002
Statement of Operations data:
Operating revenues	$	9,143	$	9,046		$	7,703		$	8,135		$	6,858
Operating income (loss)		2,396		1,852			1,039			(115	)		509
Income (loss) from continuing operations	$	1,403	$	1,109		$	657		$	(241	)	$	387
Income (loss) from discontinued operations		4		19			(16	)		—			—
Income (loss) before cumulative effect of changes in accounting principles		1,407		1,128			641			(241	)		387
Cumulative effect of changes in accounting principles (net of income taxes)		—		(30	)		32			108			13
Net income (loss) (a)	$	1,407	$	1,098		$	673		$	(133	)	$	400

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

	December 31,
(in millions)	2006		2005		2004		2003		2002
Balance Sheet data:
Current assets	$	3,433	$	3,040	$	2,321	$	2,438	$	1,805
Property, plant and equipment, net		7,514		7,464		7,536		7,106		4,698
Deferred debits and other assets		7,962		7,220		6,581		5,105		4,402
Total assets	$	18,909	$	17,724	$	16,438	$	14,649	$	10,905
Current liabilities	$	2,914	$	3,400	$	2,416	$	3,553	$	2,594
Long-term debt		1,778		1,788		2,583		1,649		2,132
Deferred credits and other liabilities		8,736		8,554		8,356		6,488		3,226
Minority interest		1		2		44		3		54
Member’s equity		5,480		3,980		3,039		2,956		2,899
Total liabilities and member’s equity	$	18,909	$	17,724	$	16,438	$	14,649	$	10,905

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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)	2006			2005			2004		2003		2002
Statement of Operations data:
Operating revenues	$	6,101		$	6,264		$	5,803	$	5,814	$	6,124
Operating income (loss)		555			(12	)		1,617		1,567		1,766
Income (loss) before cumulative effect of changes in accounting principles	$	(112	)	$	(676	)	$	676	$	702	$	790
Cumulative effect of a change in accounting principle (net of income taxes)		—			(9	)		—		5		—
Net income (loss) (a)	$	(112	)	$	(685	)	$	676	$	707	$	790

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.

	December 31,
(in millions)	2006		2005		2004		2003		2002
Balance Sheet data:
Current assets	$	1,007	$	1,024	$	1,196	$	1,313	$	1,049
Property, plant and equipment, net		10,457		9,906		9,463		9,096		8,689
Goodwill, net (a)		2,694		3,475		4,705		4,719		4,916
Noncurrent regulatory assets		532		280		240		326		515
Other deferred debits and other assets		3,084		2,806		2,077		2,837		1,662
Total assets	$	17,774	$	17,491	$	17,681	$	18,291	$	16,831
Current liabilities	$	1,600	$	2,308	$	1,764	$	1,557	$	2,023
Long-term debt, including long-term debt to financing trusts (b)		4,133		3,541		4,282		5,887		5,268
Noncurrent regulatory liabilities		2,824		2,450		2,444		2,217		1,001
Other deferred credits and other liabilities		2,919		2,796		2,451		2,288		2,451
Mandatorily redeemable preferred securities of subsidiary trusts (b)		—		—		—		—		330
Shareholders’ equity		6,298		6,396		6,740		6,342		5,758
Total liabilities and shareholders’ equity	$	17,774	$	17,491	$	17,681	$	18,291	$	16,831

(a) The changes between 2006 and 2005 and between 2005 and 2004 were primarily due to the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.

(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)	2006		2005			2004		2003		2002
Statement of Operations data:
Operating revenues	$	5,168	$	4,910		$	4,487	$	4,388	$	4,333
Operating income		866		1,049			1,014		1,056		1,093
Income before cumulative effect of a change in accounting principle	$	441	$	520		$	455	$	473	$	486
Cumulative effect of a change in accounting principle (net of income taxes)		—		(3	)		—		—		—
Net income	$	441	$	517		$	455	$	473	$	486
Net income on common stock	$	437	$	513		$	452	$	468	$	478

	December 31,
(in millions)	2006		2005		2004		2003		2002
Balance Sheet data:
Current assets	$	762	$	795	$	727	$	659	$	898
Property, plant and equipment, net		4,651		4,471		4,329		4,256		4,159
Noncurrent regulatory assets		3,896		4,454		4,836		5,238		5,546
Other deferred debits and other assets		464		366		241		232		88
Total assets	$	9,773	$	10,086	$	10,133	$	10,385	$	10,691
Current liabilities	$	978	$	936	$	748	$	676	$	1,509
Long-term debt, including long-term debt to financing trusts (a)		3,784		4,143		4,628		5,239		4,951
Noncurrent regulatory liabilities		151		68		46		12		—
Other deferred credits and other liabilities		3,051		3,235		3,313		3,442		3,342
Mandatorily redeemable preferred securities of subsidiary trusts (a)		—		—		—		—		128
Shareholders’ equity		1,809		1,704		1,398		1,016		761
Total liabilities and shareholders’ equity	$	9,773	$	10,086	$	10,133	$	10,385	$	10,691

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

Exelon

General

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

• Generation, whose business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and competitive retail sales operations.

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

• PECO, whose businesses consists of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia.

See Note 20 of the Combined Notes to Consolidated Financial Statements for further segment information.

Exelon’s corporate operations, through its business services subsidiary, BSC, provide Exelon’s business segments with a variety of support services. The costs of these services are directly charged or 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.

Exelon Corporation

Executive Overview

Financial Results. Exelon’s net income was $1,592 million in 2006 as compared to $923 million in 2005 and diluted earnings per average common share were $2.35 for 2006 as compared to $1.36 for 2005. The increases were primarily due to the following:

• a $1.2 billion impairment charge in 2005 associated with ComEd’s goodwill;

• higher margins on wholesale market sales and increased nuclear output at Generation;

• a one-time benefit of approximately $290 million to recover certain costs approved by the ICC’s July 2006 rate order and the ICC’s December 2006 amended rate order;

• unrealized mark-to-market gains on contracts not yet settled;

• a decrease in Generation’s nuclear asset retirement obligation resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily the AmerGen nuclear plants;

• increased electric revenues at PECO associated with certain scheduled rate increases;

• increased kWh deliveries, excluding the effects of weather, reflecting 2006 load growth at ComEd and PECO;

• losses recorded in 2005 for the cumulative effect of adopting Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47); and

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• a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims.

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

• a $776 million impairment charge associated with ComEd’s goodwill primarily due to the impacts of the ICC’s July 2006 rate order;

• a charge of approximately $55 million for the write-off of capitalized costs associated with the now terminated proposed merger with PSEG;

• increased severance and severance-related charges;

• unfavorable weather conditions in the ComEd and PECO service territories;

• reduced earnings from investments in synthetic fuel-producing facilities and the impairment of the associated intangible asset;

• increased depreciation and amortization expense, primarily related to CTC amortization at PECO;

• higher operating and maintenance expenses, including increased nuclear refueling outage costs, increased costs associated with incremental storm damage in the PECO service territory, expenses related to stock-based compensation as a result of adopting Financial Accounting Standards Board Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R) and the impacts of inflation;

• increased interest expense associated with the debt issued in March 2005 to fund Exelon’s pension contributions; and

• gains realized in 2005 on AmerGen’s decommissioning trust fund investments related to changes to the investment strategy.

Termination of Proposed Merger with PSEG. On December 20, 2004, Exelon entered into a Merger Agreement with PSEG, a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG would be merged with and into Exelon (Merger). On September 14, 2006, Exelon gave formal notice to PSEG that Exelon had terminated the Merger Agreement and the companies agreed to withdraw their application for Merger approval, which had been pending before the NJBPU for more than 19 months. The notice followed a number of discussions with state officials and other interested parties, which made clear that gaps separating the parties’ respective settlement positions were insurmountable. Major differences included, among other things, issues relating to rate concessions and market power mitigation. During 2006, Exelon recorded Merger-related expenses of approximately $93 million (pre-tax), of which $55 million relates to the write-off of the capitalized costs associated with the Merger. Including this $93 million of expenses, total Merger-related expenses incurred since the inception of the Merger discussions were approximately $130 million.

Financing Activities. During 2006, Exelon met its capital resource requirements primarily with internally generated cash. When necessary, Exelon obtains funds from external sources, including the capital markets, and through bank borrowings. As of December 31, 2006, Exelon, Generation, ComEd and PECO have access to revolving credit facilities with aggregate bank commitments of $1 billion, $5 billion, $1 billion and $600 million, respectively. In addition, ComEd and PECO issued First Mortgage Bonds of $1.1 billion and $300 million, respectively, in 2006. See Note 11 of the Combined Notes to Consolidated Financial Statements for further information on the credit facilities and the bond issuances.

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Regulatory and Environmental Developments. The following significant regulatory and environmental developments occurred during 2006. See Notes 4 and 18 of the Combined Notes to Consolidated Financial Statements for further information.

• ComEd Procurement Case—On January 24, 2006, the ICC approved ComEd’s procurement case, authorizing ComEd to procure electricity after 2006 through a “reverse-auction” competitive bidding process and to recover the costs from retail customers with no markup. The first auction took place in September 2006. As a result of the auction, ComEd has entered into supplier forward contracts with various suppliers including Generation. The ICC order is under appeal.

• Illinois Rate Freeze Extension Proposal—In 2006 and 2007, various bills, amendments and “compromise” legislation were separately passed by the Illinois House and the Illinois Senate including, in the Illinois House, an extension of the Illinois transition period rate freeze with a rollback of rates to 2006 levels. However, the Illinois General Assembly adjourned on January 9, 2007 without taking further action on such bills. As a result, all pending legislation expired. ComEd believes any rate rollback and freeze legislation, if proposed again and enacted into law, would have serious detrimental effects on Illinois, ComEd and consumers of electricity. ComEd believes such legislation would violate Federal law and the U.S. Constitution, and ComEd is prepared to vigorously challenge any such legislation in court.

• ComEd Residential Rate Stabilization—On December 20, 2006, the ICC approved a residential rate stabilization program that allows residential customers the choice to limit the impact of any rate increase over the next three years. For customers choosing to participate in the program, electric rate increases would be capped at 10% in each of 2007, 2008 and 2009. Costs that exceed the caps would be deferred and recovered over three years from 2010 to 2012. Deferred balances will be assessed an annual carrying charge of 3.25%. If ComEd’s rate increases are less than the caps in 2008 and 2009, ComEd would begin to recover deferred amounts up to the caps with carrying costs. This order also strongly encouraged, but did not require, ComEd to make contributions totaling $30 million to environmental and customer assistance programs. ComEd is currently evaluating this request. This order is subject to rehearing and appeal.

• ComEd Rate Case—On July 26, 2006, the ICC issued its order in the Rate Case approving a revenue increase of approximately $8 million and the recovery of several items that previously were recorded as expense. On December 20, 2006, the ICC approved an amended order on the rehearing of the Rate Case allowing an additional revenue increase of approximately $74 million, including a partial return on the pension asset, for a total rate increase of $83 million. ComEd and various other parties have appealed the rate order to the courts. As a result of the July 26, 2006 ICC rate order, ComEd recorded an after-tax impairment charge of $776 million associated with the write-off of goodwill.

• Nuclear Fleet Inspection—In February 2006, Exelon and Generation launched an initiative across its nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium into the environment. The initiative was in response to the detection of tritium in water samples taken related to leaks at the Braidwood, Byron and Dresden nuclear generating stations in Illinois. On September 28, 2006, Generation announced the final results of the assessment, concluding that no active leaks had been identified at any of Generation’s 11 nuclear plants and no detectable tritium had been identified beyond any of the plants’ boundaries other than from permitted discharges, with the exception of Braidwood where past accidental tritiated water spills have been identified and state-approved cleanup work continues. The assessment further concluded that none of the tritium concentrations identified in the assessment pose a health or safety threat to the public or to Generation’s employees or contractors.

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Outlook for 2007 and Beyond.

Exelon’s future financial results will be affected by a number of factors, including the following:

• If the price at which ComEd is allowed to sell electricity beginning in 2007 is set below ComEd’s cost to procure and deliver electricity, there will be material adverse consequences to ComEd, including possible bankruptcy, which could result in material adverse consequences to Exelon and, in the event of a ComEd bankruptcy filing, possibly material adverse consequences to Generation. The ICC’s unanimous approval of the reverse-auction process, barring any adverse decision in the pending appeals or change in law, should provide ComEd with stability and greater certainty that it will be able to procure electricity and pass through the costs of that electricity to ComEd’s customers beginning in 2007 through a transparent market mechanism in the reverse-auction competitive bidding process.

• PECO was subject to electric rate caps on its transmission and distribution rates through December 31, 2006 and is subject to caps on its generation rates through December 31, 2010. PECO’s transmission and distribution rates will continue in effect until PECO files a rate case or there is some other specific regulatory action to adjust the rates. There are no current proceedings to do so. PECO is, however, involved in proceedings involving annual changes in its electric and gas universal service fund cost charges, its electric CTC/intangible transition charge reconciliation mechanism, and its purchased gas cost rate, all of which are designed to fully recover PECO’s applicable costs on a dollar-for-dollar basis.

• Effective January 1, 2007, in accordance with its 1998 restructuring settlement with the PAPUC, PECO implemented an electric generation rate increase that will result in approximately $190 million of additional operating revenues in 2007 as compared to 2006 and a corresponding increase in purchased power from affiliate, in accordance with PECO’s PPA with Generation, with no resulting impact on pre-tax operating income. The impact of this rate increase on Exelon will be an increase in operating revenues and pre-tax operating income of approximately $190 million. The impact on Generation will be an increase in operating revenues from affiliates and pre-tax operating income of approximately $190 million.

• Generation is exposed to commodity price risk associated with the unhedged portion of its electricity trading portfolio. Generation enters into derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2007 and 2008. However, Generation is exposed to relatively greater commodity price risk in the subsequent years for which a larger portion of its electricity portfolio may be unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years as well.

• The PPA between Generation and PECO expires at the end of 2010. Current market prices for electricity have increased significantly over the past few years due to the rise in natural gas and fuel prices. As a result, PECO customers’ generation rates are below current wholesale energy market prices and Generation’s margins on sales in excess of ComEd’s and PECO’s requirements have improved historically due to its significant capacity of low-cost nuclear generating facilities. Generation’s ability to maintain those margins will depend on future fossil fuel prices and its ability to obtain high capacity factors at its nuclear plants.

• Federal and state governing bodies have begun to introduce, and in some cases approve, legislation mandating the future use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal. The extent of the use of these renewable and alternative fuel sources varies by state and could change. The future requirement to use these renewable and alternative fuel sources for some portion of ComEd’s and PECO’s distribution sales could result in increased fuel costs and capital expenditures.

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• Select northeast and mid-Atlantic states have developed a model rule, via the RGGI, to regulate carbon emissions from fossil-fired generation in participating states starting in 2009. Federal and/or state legislation to regulate carbon emissions could occur in the future. If these plans become effective, Exelon may incur costs in further limiting the emissions from certain of its fossil-fuel fired facilities or in procuring emission allowance credits issued by various governing bodies. However, Exelon may benefit from stricter emission standards due to its significant nuclear capacity, which is not anticipated to be affected by the proposed emission standards.

• Exelon anticipates that it will be subject to the ongoing pressures of rising operating expenses due to increases in costs such as medical benefits and rising payroll costs due to inflation. Also, Exelon will continue to incur significant capital costs associated with its commitment to produce and deliver energy reliably to its customers. Increasing capital costs may include the price of uranium which fuels the nuclear facilities and continued capital investment in Exelon’s aging distribution infrastructure and generating facilities. Exelon is determined to operate its businesses responsibly and to appropriately manage its operating and capital costs while serving its customers and producing value for its shareholders.

• Exelon pursues growth opportunities that are consistent with its disciplined approach to investing to maximize earnings and cash flows. On September 29, 2006, Generation notified the NRC that Generation will begin the application process for a combined construction and operating license that would allow for the possible construction of a new nuclear plant at an as-yet unnamed location in Texas. The filing of the letter with the NRC launches a process that “preserves for Exelon the option” to develop a new nuclear plant in Texas without immediately committing to the full project. Exelon has not decided to build a new nuclear plant. Among the various conditions that must be resolved before any formal decision to build is made are a permanent solution to spent nuclear fuel disposal, broad public acceptance of a new nuclear plant and assurances that a new plant using new technology can be financially successful. Exelon expects to submit the application to the NRC for the combined construction and operating license in 2008.

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 Combined Notes to Consolidated Financial Statements.

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

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).

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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 decommissioning costs from the decommissioning cost studies discussed above, which were prepared using year-of-estimate amounts, 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 a periodic basis.

Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various cost, decommissioning alternative and timing scenarios. Probabilities assigned to cost levels include an assessment of the likelihood of actual costs plus 20% or minus 15% over the base cost scenario. Probabilities assigned to decommissioning alternatives assess the likelihood of performing DECON (a method of decommissioning in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed and safely buried in a low-level radioactive waste landfill or decontaminated to a level that permits property to be released for unrestricted use shortly after the cessation of operations), Delayed DECON or SAFSTOR (a method of decommissioning in which the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated to levels that permit release for unrestricted use) procedures. Probabilities assigned to the timing scenarios incorporate the likelihood of continued operation through current license lives or through anticipated license renewals. Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of spent nuclear fuel for permanent disposal.

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 an update to an ARO results in a decrease, and that unit does not have an underlying ARC, that change in the ARO may be recognized 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 $300 million. Under SFAS No. 143, the nuclear decommissioning obligation is adjusted on a periodic 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 the Combined Notes to Consolidated Financial Statements.

Conditional ARO (Exelon, Generation, ComEd and PECO)

As of December 31, 2005, the Registrants adopted 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

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conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, the Registrants are required to record a conditional ARO at its estimated fair value if that fair value can be reasonably estimated.

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 values of the conditional AROs were 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 and the associated regulatory assets recorded at Exelon, ComEd and PECO. The liabilities associated with conditional AROs will be adjusted on a periodic 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 Operations of the Registrants. For more information regarding the adoption and ongoing application of FIN 47, see Notes 1 and 13 of the Combined Notes to Consolidated Financial Statements.

Asset Impairments (Exelon, Generation, ComEd and PECO)

Goodwill (Exelon and ComEd)

Exelon and ComEd have goodwill which relates to the acquisition of ComEd under the PECO/Unicom Merger. Under the provisions of SFAS No. 142, Exelon and ComEd perform assessments for impairment of their goodwill at least annually or more frequently if events or circumstances indicate that it is “more likely than not” that goodwill might be impaired, such as a significant negative regulatory outcome. 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. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information.

Due to the significant negative impact of the ICC’s July 26, 2006 order in ComEd’s Rate Case to the future cash flows and value of ComEd, an interim impairment assessment was completed during the third quarter of 2006. Based on the results of ComEd’s interim goodwill impairment analysis, Exelon and ComEd recorded an impairment charge of $776 million associated with the write-off of the goodwill. Exelon and ComEd performed their annual goodwill impairment assessment in the fourth quarter of 2006 and determined that goodwill was not further impaired. Future developments relating to ComEd’s ongoing regulatory and/or legislative items could also be relevant to future goodwill impairment analyses and may lead to further impairments, which could be material. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information regarding the Rate Case.

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. Additionally, ComEd’s estimate of its fair value was compared to a fair value estimate determined by a third-party valuation firm. Changes in assumptions regarding variables, including post-2006 rate regulatory structure, ComEd’s capital structure, changing interest rates, utility sector market performance, operating and

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capital expenditure requirements and other factors, or in the assessment of how they interrelate could produce a different impairment result, which could be material. For example, a hypothetical decrease of 10% in ComEd’s expected discounted cash flows would result in additional impairment for both ComEd and Exelon of approximately $800 million. 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, Generation, ComEd and PECO)

Exelon, Generation, ComEd, and PECO 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, costs of fuel and the expected operations of assets. 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, Generation, ComEd and PECO)

Exelon, Generation, ComEd, and PECO had investments, including investments held in nuclear decommissioning trust funds, recorded as of December 31, 2006. The Registrants 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, the Registrants evaluate, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as 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. Beginning in 2006, and in connection with the issuance of FASB Staff Position FAS 115-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (FSP 115-1), Generation considers all nuclear decommissioning trust fund investments in an unrealized loss position to be other-than-temporarily impaired. As a result of certain NRC restrictions, Generation is unable to demonstrate its ability and intent to hold the nuclear decommissioning trust fund investments through a recovery period and, accordingly, recognizes any unrealized holding losses immediately.

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

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, the estimated service lives 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 the 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

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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. Generation also periodically evaluates the estimated service lives of its fossil fuel generating facilities based on feasibility assessments as well as economic and capital requirements. A change in depreciation estimates resulting from Generation’s extension or reduction of the estimated service lives could have a significant effect on Generation’s results of operations.

PECO is required to file a depreciation rate study at least every five years with the PAPUC. In August 2005, PECO filed a depreciation rate study with the PAPUC for both its electric and gas assets, which resulted in the implementation of new depreciation rates effective March 2006. The impact of the new rates was not material.

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

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO, and BSC employees, except for those employees of Generation’s wholly owned subsidiary, AmerGen, who participate in the separate AmerGen-sposored defined benefit pension plan and other postretirement welfare benefit plan. See Note 14—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding the accounting for the defined benefit pension plans and postretirement 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 and AmerGen utilize assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the remaining service period, rate of compensation increases and the anticipated rate of increase in health care costs, in order to measure the plan obligations and costs to be recognized related to these plans.

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% for 2006, 2005, and 2004. The weighted average EROA assumption used in calculating other postretirement benefit costs was 8.15% and 8.30% in 2006 and 2005, respectively, and a range of 8.33% to 8.35% in 2004. 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 average remaining service period of defined pension plan participants was 13.5 years, 13.8 years and 15.1 years for the years ended December 31, 2006, 2005 and 2004, respectively. The average remaining service period of postretirement benefit plan participants related to eligibility age was 7.3 years, 7.5 years and 8.7 years for the years ended December 31, 2006, 2005 and 2004, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 10.3 years, 10.9 years and 11.9 years for the years ended December 31, 2006, 2005 and 2004, respectively.

The discount rate for determining the pension benefit obligations was 5.90%, 5.60% and 5.75% at December 31, 2006, 2005 and 2004, respectively. The discount rate for determining the other postretirement benefit obligations was 5.85%, 5.60% and 5.75% at December 31, 2006, 2005 and 2004, respectively. The discount rate at December 31, 2004 was 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 benefit payments. At December 31, 2006 and 2005, the discount rate was

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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 benefit obligations. The spot rates are used to discount the estimated distributions under the pension and other postretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve.

Exelon will use a discount rate and EROA of 5.90% and 8.75%, respectively, for estimating its 2007 pension costs. Additionally, Exelon will use a discount rate and expected return on plan assets of 5.85% and 7.87%, respectively, for estimating its 2007 other postretirement benefit costs.

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, 2006		Impact on Pension Liability at December 31, 2006		Impact on 2007 Pension Cost
Pension benefits
Decrease discount rate by 0.5%	$	720	$	720	$	57
Decrease rate of return on plan assets by 0.5%		—		—		47
Change in Actuarial Assumption	Impact on Other Postretirement Benefit Obligation at December 31, 2006		Impact on Postretirement Benefit Liability at December 31, 2006		Impact on 2007 Postretirement Benefit Cost
Postretirement benefits
Decrease discount rate by 0.5%	$	225	$	225	$	26
Decrease rate of return on plan assets by 0.5%		—		—		7

Assumed health care cost trend rates also have a significant effect on the costs reported for Exelon’s and AmerGen’s postretirement benefit plans. A one-percentage point change in assumed health care cost trend rates would have had the following effects on the December 31, 2006 postretirement benefit obligation and estimated 2006 costs (dollars in millions):

Change in Actuarial Assumption	Impact on Other Postretirement Benefit Obligation at December 31, 2006			Impact on 2006 Total Service and Interest Cost Components
Increase assumed health care cost trend by 1%	$	45		$	418
Decrease assumed health care cost trend by 1%		(37	)		(345	)

Extending the year at which the ultimate health care trend rate of 5% is forecasted to be reached from 2012 to 2017 would have had the following effects on the December 31, 2006 postretirement benefit obligation and estimated 2006 costs (dollars in millions):

Change in Actuarial Assumption	Impact on Other Postretirement Benefit Obligation at December 31, 2006		Impact on 2006 Total Service and Interest Cost Components
Increase the year at which the ultimate health care trend rate of 5% is forecasted to be reached from 2012 to 2017	$	234	$	22

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The assumptions are reviewed annually 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.

Regulatory Accounting (Exelon, ComEd and PECO)

Exelon, ComEd and PECO account for their regulated electric and gas operations in accordance with SFAS No. 71, which requires Exelon, ComEd, and PECO to reflect the effects of rate regulation in their financial statements. 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. 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, 2006, 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 and the recognition of a one-time extraordinary item in their Consolidated Statements of Operations and Comprehensive Income (Loss). The impact of not meeting the criteria of SFAS No. 71 could be material to the financial statements of Exelon, ComEd and PECO. At December 31, 2006, the income statement gain could have been as much as $2.3 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities had it been determined that ComEd could no longer maintain regulatory assets and liabilities under SFAS No. 71. Similarly, at December 31, 2006, the income statement charge could have been as much as $3.7 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities had it been determined that PECO could no longer maintain regulatory assets and liabilities under SFAS No. 71. In that event, Exelon would record an income statement gain or charge in an equal amount related to ComEd’s and/or PECO’s regulatory assets and liabilities in addition to a charge against other comprehensive income of up to $1.4 billion (before taxes) related to Exelon’s regulatory assets associated with its defined benefit postretirement plans. The impacts and resolution of the above items could lead to an additional impairment of ComEd’s goodwill, which would be significant and at least partially offset the extraordinary gain discussed above. A write-off of regulatory assets and liabilities could limit the ability of ComEd and PECO to pay dividends under Federal and state law. See Notes 4, 8 and 19 of the Combined Notes to Consolidated Financial Statements for further information regarding regulatory issues, ComEd’s goodwill and the significant regulatory assets and liabilities of Exelon, ComEd and PECO, respectively.

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 and the ability to recover costs through regulated rates.

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

The Registrants may 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 the utilization of its available generating capability and the supply of wholesale energy to its affiliates. Generation

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also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk exposure associated with forward energy commodity prices. Additionally, Generation enters into energy-related derivatives for trading purposes. ComEd has derivatives related to one wholesale contract and certain other contracts to manage the market price exposures to several wholesale contracts that extend into 2007, which is beyond the expiration of ComEd’s PPA with Generation. ComEd does not enter into derivatives for speculative or trading purposes. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

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 occur. Amounts recorded in earnings are included in revenue, purchased power or fuel in the consolidated statements of income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the statement of cash flows, depending on the underlying nature of the Registrant’s hedged items.

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. If it was determined that a transaction designated as a “normal” purchase 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. In September 2006, Generation participated in and won portions of the ComEd and Ameren procurement auctions. As a result of the expiration of Generation’s PPA with ComEd at the end of 2006 and the results of the auctions, beginning in 2007, Generation will sell more power through bilateral agreements with other new and existing counterparties. ComEd also entered into agreements with thirteen other suppliers as part of the auction. Generation’s and ComEd’s agreements meet the normal purchases and normal sales exception.

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

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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.

See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk—Normal Operations and Hedging Activities for further information regarding sensitivity analysis related to market price exposure.

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

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

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 Registrants make in accounting for contingencies and the gains and losses that they record upon the ultimate resolution of these uncertainties could 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. 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, 2006 reflect the probable expected outcome of pending tax matters in accordance with SFAS No. 5, “Accounting for Contingencies,” SFAS No. 109, “Accounting for Income Taxes,” and Statement of Financial Accounting Concepts No. 6, “Elements of Financial Statements—a replacement of FASB Concepts Statement No. 3 (incorporating an amendment of FASB Concepts Statement No. 2)”, 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

Environmental investigation and remediation 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, the timing of the remediation work, changes in technology, regulations and the requirements of local governmental authorities.

Other, Including Personal Injury Claims

The Registrants are self-insured for general liability, automotive liability, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained.

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The Registrants have reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Projecting 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 litigation and possible legislative measures in the United States, could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material effect on the Registrants’ results of operations, financial position and cash flows.

Exelon and Generation have a reserve for asbestos-related bodily injury claims for open claims presented to Generation as of December 31, 2006 and 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 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, Generation, ComEd and PECO)

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. 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.

Stock-Based Compensation Cost (Exelon, Generation, ComEd and PECO)

On January 1, 2006, Exelon adopted SFAS No. 123-R, which requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost is measured on the fair value of the equity or liability instruments at the date of grant and amortized over the vesting period. The fair value of stock options on the date of grant is estimated using the Black-Scholes-Merton option-pricing model, which requires assumptions such as dividends yield, expected volatility, risk-free interest rate, expected life and forfeiture rate. The fair value of performance share awards granted in 2006 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year, which requires assumptions regarding Exelon’s

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total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon’s common stock and all stocks represented in these indices. If the actual results of the cash-settled performance share awards differ significantly from the estimates, the Consolidated Financial Statements could be materially affected. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information.

Revenue Recognition (Exelon, Generation, ComEd and PECO)

Revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The determination of Generation’s, ComEd’s and PECO’s retail 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. 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 the retail business, 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. 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, 2006 Compared to Year Ended December 31, 2005

Results of Operations—Exelon

	2006			2005			Favorable (unfavorable) variance
Operating revenues	$	15,655		$	15,357		$	298
Operating expenses
Purchased power and fuel		5,232			5,670			438
Operating and maintenance		3,868			3,694			(174	)
Impairment of goodwill		776			1,207			431
Depreciation and amortization		1,487			1,334			(153	)
Taxes other than income		771			728			(43	)
Total operating expenses		12,134			12,633			499
Operating income		3,521			2,724			797
Other income and deductions
Interest expense		(616	)		(513	)		(103	)
Interest expense to affiliates, net		(264	)		(316	)		52
Equity in losses of unconsolidated affiliates		(111	)		(134	)		23
Other, net		266			134			132
Total other income and deductions		(725	)		(829	)		104
Income from continuing operations before income taxes		2,796			1,895			901
Income taxes		1,206			944			(262	)
Income from continuing operations		1,590			951			639
Income from discontinued operations, net of income taxes		2			14			(12	)
Income before cumulative effect of a change in accounting principle		1,592			965			627
Cumulative effect of changes in accounting principles		—			(42	)		42
Net income	$	1,592		$	923		$	669
Diluted earnings per share	$	2.35		$	1.36		$	0.99

Net Income. Exelon’s net income for 2006 reflects higher realized prices on market sales and increased nuclear output at Generation; a one-time benefit of approximately $158 million to recover previously incurred severance costs approved by the December 2006 amended ICC rate order; a one-time benefit of approximately $130 million to recover certain costs approved by the July 2006 ICC rate order; a decrease in Generation’s nuclear ARO resulting from changes in management’s assessment of the probabilities associated with the anticipated timing of cash flows to decommission primarily AmerGen nuclear plants; unrealized mark-to-market gains; increased electric revenues at PECO associated with certain authorized rate increases; and increased kWh deliveries, excluding the effects of weather, reflecting load growth at ComEd and PECO. These increases were partially offset by a $776 million impairment charge associated with ComEd’s goodwill; unfavorable weather conditions in both the ComEd and PECO service territories; a charge of approximately $55 million for the write-off of capitalized costs associated with the terminated proposed Merger with PSEG; increased severance and severance-related charges; losses from investments in synthetic fuel-producing facilities; increased depreciation and amortization expense, including CTC amortization at PECO; and higher operating and maintenance expenses including increased costs associated with storm damage in the PECO service territory, increased nuclear refueling outage costs, increased stock-based compensation expense as a result of adopting SFAS No. 123-R, and the impacts of

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inflation. Exelon’s net income for 2005 reflects an impairment charge of $1.2 billion associated with ComEd’s goodwill; unrealized mark-to-market losses; losses of $42 million for the cumulative effect of adopting FIN 47; favorable tax settlements at Generation and PECO; and gains realized on AmerGen’s decommissioning trust fund investments related to changes in the investment strategy.

Operating Revenues. Operating revenues increased primarily due to an increase in wholesale and retail electric sales at Generation due to an increase in market prices; higher nuclear output; electric rate increases at PECO; and higher kWh deliveries at ComEd and PECO, excluding the effects of weather. These increases were partially offset by unfavorable weather conditions in the ComEd and PECO service territories. See further analysis and discussion of operating revenues by segment below.

Purchased Power and Fuel Expense. Purchased power and fuel expense decreased due to lower volumes of power purchased in the market and decreased fossil generation, partially offset by overall higher market energy prices and higher natural gas and oil prices. Purchased power represented 20% of Generation’s total supply in 2006 compared to 22% for 2005. See further analysis and discussion of purchased power and fuel expense by segment below.

Operating and Maintenance Expense. Operating and maintenance expense increased primarily due to a charge of approximately $55 million for the write-off of capitalized costs associated with the terminated proposed Merger with PSEG; increased nuclear refueling outage costs; increased severance and severance-related charges; increased stock-based compensation expense as a result of adopting SFAS No. 123-R; and the impacts from inflation. These increases were partially offset by a one-time benefit of $201 million to recover certain costs approved by the ICC’s July 2006 rate order and the ICC’s December 2006 amended rate order; the impact of the reduction in Generation’s estimated nuclear asset retirement obligation; mark-to-market gains associated with Exelon’s investment in synthetic fuel-producing facilities; and a charge for a reserve recorded by Generation in 2005 for estimated future asbestos-related bodily injury claims. See further discussion of operating and maintenance expenses by segment below.

Impairment of Goodwill. During 2006, ComEd recorded a $776 million impairment charge associated with its goodwill primarily due to the impacts of the ICC’s July 2006 rate order. During 2005, in connection with the annually required assessment of goodwill for impairment, ComEd recorded a $1.2 billion charge.

Depreciation and Amortization Expense. Depreciation and amortization expense increased primarily due to additional CTC amortization at PECO and additional plant placed in service.

Taxes Other Than Income. Taxes other than income increased primarily due to a reduction in 2005 of previously established real estate tax reserves at PECO and Generation and a net increase in utility revenue taxes at ComEd and PECO in 2006, partially offset by favorable state franchise tax settlements at PECO in 2006.

Other Income and Deductions. The change in other income and deductions reflects increased interest expense associated with the debt issued in 2005 to fund Exelon’s voluntary pension contribution; higher interest rates on variable rate debt outstanding; higher interest expense on Generation’s one-time fee for pre-1983 spent nuclear fuel obligations to the DOE; an interest payment to the IRS associated with the settlement of a tax matter at Generation; and a one-time benefit of $87 million approved by the ICC’s July 2006 rate order to recover previously incurred debt expenses to retire debt early .

Effective Income Tax Rate. The effective income tax rate from continuing operations was 43.1% for 2006 compared to 49.8% for 2005. The goodwill impairment charges increased the effective income

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tax rate from continuing operations by 9.7% and 22.3% for 2006 and 2005, respectively. See Note 12 of the Combined 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. 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 (for Sithe and Enterprises) and Generation’s (for Sithe) Consolidated Statements of Operations and Comprehensive Income. See Notes 2 and 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe and certain Enterprises businesses as discontinued operations. The results of Sithe are included in the Generation discussion below.

The income from discontinued operations decreased by $12 million for 2006 compared to 2005 primarily due to the gain on the sale of Sithe in 2005 partially offset by an adjustment to the gain on the sale of Sithe in 2006 as a result of the expiration of certain tax indemnifications.

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. See Note 13 of the Combined Notes to Consolidated Financial Statements for further discussion of the adoption of FIN 47.

Results of Operations by Business Segment

The comparisons of 2006 and 2005 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

	2006			2005			Favorable (unfavorable) variance
Generation	$	1,403		$	1,109		$	294
ComEd		(112	)		(676	)		564
PECO		441			520			(79	)
Other (a)		(142	)		(2	)		(140	)
Total	$	1,590		$	951		$	639

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

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

	2006			2005			Favorable (unfavorable) variance
Generation	$	1,407		$	1,128		$	279
ComEd		(112	)		(676	)		564
PECO		441			520			(79	)
Other (a)		(144	)		(7	)		(137	)
Total	$	1,592		$	965		$	627

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

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Net Income (Loss) by Business Segment

	2006			2005			Favorable (unfavorable) variance
Generation	$	1,407		$	1,098		$	309
ComEd		(112	)		(685	)		573
PECO		441			517			(76	)
Other (a)		(144	)		(7	)		(137	)
Total	$	1,592		$	923		$	669

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

Results of Operations—Generation

	2006			2005			Favorable (unfavorable) variance
Operating revenues	$	9,143		$	9,046		$	97
Operating expenses
Purchased power and fuel		3,978			4,482			504
Operating and maintenance		2,305			2,288			(17	)
Depreciation and amortization		279			254			(25	)
Taxes other than income		185			170			(15	)
Total operating expenses		6,747			7,194			447
Operating income		2,396			1,852			544
Other income and deductions
Interest expense		(159	)		(128	)		(31	)
Equity in losses of unconsolidated affiliates		(9	)		(1	)		(8	)
Other, net		41			95			(54	)
Total other income and deductions		(127	)		(34	)		(93	)
Income from continuing operations before income taxes		2,269			1,818			451
Income taxes		866			709			(157	)
Income from continuing operations		1,403			1,109			294
Discontinued operations
Gain on disposal of discontinued operations		4			19			(15	)
Income from discontinued operations		4			19			(15	)
Income before cumulative effect of changes in accounting principles		1,407			1,128			279
Cumulative effect of changes in accounting principles		—			(30	)		30
Net income	$	1,407		$	1,098		$	309

Net Income. Generation’s net income for 2006 compared to 2005 increased due to higher revenue, net of purchased power and fuel expense partially offset by higher operating and maintenance expense, higher depreciation expense, higher interest expense and lower other income. The increase in Generation’s revenue, net of purchased power and fuel expense was due to realized revenues associated with forward sales contracts entered into in prior periods which were recognized at higher prices, combined with lower purchased power and fuel expense due to the impact of higher

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nuclear output. Unlike the energy delivery business, the effects of unusually warm or cold weather on Generation depend on the nature of its market position at the time of the unusual weather. Generation’s net income for 2006 and 2005 reflects income from discontinued operations of $4 million and $19 million (after tax), respectively.

Operating Revenues. For 2006 and 2005, Generation’s sales were as follows:

Revenue	2006		2005		Variance			% Change
Electric sales to affiliates	$	4,674	$	4,775	$	(101	)	(2.1	)%
Wholesale and retail electric sales		3,640		3,341		299		8.9	%
Total energy sales revenue		8,314		8,116		198		2.4	%
Retail gas sales		540		613		(73	)	(11.9	)%
Trading portfolio		14		17		(3	)	(17.6	)%
Other revenue (a)		275		300		(25	)	(8.3	)%
Total revenue	$	9,143	$	9,046	$	97		1.1	%

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

Sales (in GWhs)	2006	2005	Variance		% Change
Electric sales to affiliates	119,354	121,961	(2,607	)	(2.1	)%
Wholesale and retail electric sales	71,326	72,376	(1,050	)	(1.5	)%
Total sales	190,680	194,337	(3,657	)	(1.9	)%

Trading volumes of 31,692 GWhs and 26,924 GWhs for 2006 and 2005, respectively, are not included in the table above.

Electric sales to affiliates. Revenue from sales to affiliates decreased $101 million in 2006 as compared to 2005. The decrease in revenue from sales to affiliates was primarily due to a $95 million decrease from lower electric sales volume, as well as a net $6 million decrease resulting from lower prices.

In the ComEd territories, lower volumes resulted in a $115 million decrease in revenues as a result of lower demand resulting from milder weather year over year. In addition, price decreases totaling $128 million were a result of lower peak prices under the ComEd PPA.

In the PECO territories, the higher volumes resulted in increased revenues of $20 million due to higher usage. The favorable price variance of $122 million was primarily the result of the scheduled PAPUC-approved generation rate increase as well as to a lesser degree a change in the mix of average pricing related to the PPA with PECO. On January 1, 2007, a scheduled electric generation rate increase will take effect, which represents the last scheduled rate increase through 2010 under PECO’s 1998 restructuring settlement. This rate increase will have a favorable effect on Generation’s operating income in future years.

Wholesale and retail electric sales. The changes in Generation’s wholesale and retail electric sales for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
Price	$	353
Volume		(54	)
Increase in wholesale and retail electric sales	$	299

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Wholesale and retail sales increased $299 million due to an increase in realized revenues associated with forward sales entered into in prior periods, which were recognized at higher prices for the year ended December 2006, as compared to the same period in 2005, offset by a reduction in volumes sold into the market as a result of lower supply.

Retail gas sales. Retail gas sales decreased $73 million primarily due to lower volumes for 2006 compared to 2005, resulting in a $69 million decrease. Additionally, there was a decrease of $4 million due to lower realized prices for 2006 compared to 2005.

Other revenues. The decrease in 2006 was primarily due to a decrease in fossil fuel sales.

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

Supply Source (in GWhs)	2006	2005	Variance		% Change
Nuclear generation (a)	139,610	137,936	1,674		1.2	%
Purchases—non-trading portfolio	38,297	42,623	(4,326	)	(10.1	)%
Fossil and hydroelectric generation	12,773	13,778	(1,005	)	(7.3	)%
Total supply	190,680	194,337	(3,657	)	(1.9	)%

(a) Represents Generation's proportionate share of the output of its nuclear generating plants, including Salem, which is operated by PSEG Nuclear.

The changes in Generation’s purchased power and fuel expense for 2006 compared to 2005 consisted of the following:

(in millions)	Price			Volume			Increase (Decrease)
Purchased power costs	$	(81	)	$	(319	)	$	(400	)
Generation costs		38			4			42
Fuel resale costs		34			(65	)		(31	)
Mark-to-market		n.m.			n.m.			(115	)
Decrease in purchased power and fuel expense							$	(504	)

n.m. Not meaningful

Purchased Power Costs. Purchased power costs include all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Generation experienced a decrease of $319 million due to lower volumes of purchased power in the market as a result of a lower demand from affiliates. Additionally, overall lower prices paid for purchased power in 2006 compared to 2005 resulted in a $81 million decrease.

Generation Costs. Generation costs include fuel costs for internally generated energy. Generation experienced overall higher generation costs in 2006 compared to 2005 due to increased prices related to nuclear and fossil fuel generation, resulting in a $38 million increase.

Fuel Resale Costs. Fuel resale costs include retail gas purchases and wholesale fossil fuel expenses. The changes in Generation’s fuel resale costs in 2006 compared to 2005 were a result of a $65 million decrease in the retail gas business resulting from lower volumes, partially offset by overall higher prices paid for gas.

Mark-to-market. Mark-to-market gains on power derivative activities were $180 million in 2006 compared to losses of $12 million in 2005. Mark-to-market losses on fuel derivative activities were $77 million in 2006 compared to zero in 2005.

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Generation’s average margin per MWh of electricity sold for 2006 and 2005 was as follows:

($/MWh)	2006		2005		% Change
Average electric revenue
Electric sales to affiliates	$	39.16	$	39.15	n.m.
Wholesale and retail electric sales		51.03		46.16	10.6	%
Total—excluding the trading portfolio		43.60		41.76	4.4	%
Average electric supply cost (a)—excluding the trading portfolio	$	18.02	$	20.11	(10.4	)%
Average margin—excluding the trading portfolio	$	25.58	$	21.65	18.2	%

(a) 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.

n.m. Not meaningful

Nuclear fleet operating data and purchased power cost data for 2006 and 2005 were as follows:

	2006			2005
Nuclear fleet capacity factor (a)		93.9	%		93.5	%
Nuclear fleet production cost per MWh (a)	$	13.85		$	13.03

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

Although total refueling outage days increased during 2006 compared to 2005, the nuclear fleet capacity factor for the Generation-operating nuclear fleet increased due to fewer non-refueling outage days during 2006 compared to 2005. For 2006 and 2005, non-refueling outage days totaled 71 and 112, respectively, and refueling outage days totaled 237 and 217, respectively. Higher costs for nuclear fuel, costs associated with the additional planned refueling outage days, higher costs for refueling outage inspection and maintenance activities, costs for the tritium-related expenses, an NRC fee increase, and inflationary cost increases for normal plant operations and maintenance offset the higher number of MWh’s generated resulting in a higher production cost per MWh produced for 2006 as compared to 2005. There were ten planned refueling outages and sixteen non-refueling outages during 2006 compared to nine planned refueling outages and twenty-five non-refueling outages during 2005 at the Generation-operated nuclear stations.

Operating and Maintenance Expense. The increase in operating and maintenance expense for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
Pension, payroll and benefit costs	$	153
Contractor expenses		22
Nuclear refueling outage costs including the co-owned Salem plant		19
NRC fees		11
Godley contribution		11
Tritium-related expense		9
Reduction in ARO (a)		(149	)
2005 accrual for estimated future asbestos-related bodily injury claims (b)		(43	)
2005 co-owner settlement with PSEG related to postretirement benefits		(17	)
Other		1
Increase in operating and maintenance expense	$	17

(a) For further discussion, see Note 13 of the Combined Notes to Consolidated Financial Statements.

(b) For further discussion, see Note 18 of the Combined Notes to Consolidated Financial Statements.

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The $17 million increase in operating and maintenance expense in 2006 compared to 2005 was primarily due to a $153 million increase in various payroll-related expenses, including increased stock-based compensation expense of $41 million primarily as a result of the adoption of SFAS No. 123-R as of January 1, 2006 and increased direct and allocated costs related to payroll, severance, pension and other postretirement benefits, a $22 million period-over-period increase in contractor costs, primarily related to staff augmentation and recurring maintenance work at Nuclear and Power, a $19 million increase in nuclear refueling outage costs associated with the additional planned refueling outage days during 2006 as compared to 2005, and higher costs for inspection and maintenance activities. Additionally, on December 22, 2006, as a gesture of goodwill and corporate citizenship, Generation contributed approximately $11 million into an escrow account to assist the Godley Public Water District with the installation of a new public drinking water system for the Village of Godley.

Depreciation and Amortization. The increase in depreciation and amortization expense for 2006 compared to 2005 was a result of recent capital additions.

Taxes Other Than Income. The increase in taxes other than income incurred during 2006 compared to 2005 was primarily due to increasing the property tax reserve for 2006 property taxes for Byron, Clinton and Dresden, higher payroll related taxes which were the result of higher payroll costs for 2006 and a reduction recorded in 2005 of a previously established real estate reserve associated with the settlement over the TMI real estate assessment. The increases were partially offset by a sales and use tax reserve recorded during the third quarter of 2005 and a gas revenue tax adjustment recorded during the fourth quarter of 2005.

Interest Expense. The increase in interest expense during 2006 as compared to 2005 was attributable to higher variable interest rates on debt outstanding, higher interest expense on Generation’s one-time fee for spent nuclear fuel obligations to the DOE and an interest payment made to the IRS in settlement of a tax matter.

Other, Net. The decrease in other income in 2006 compared to 2005 was primarily due to gains realized in the second quarter of 2005 totaling $36 million related to the decommissioning trust fund investments for the AmerGen plants due to changes in Generation’s investment strategy.

Effective Income Tax Rate. The effective income tax rate from continuing operations was 38.2% for 2006 compared to 39.0% for 2005. See Note 12 of the Combined Notes to 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. Accordingly, the results of operations and the gain on the sale of Sithe have been presented as discontinued operations within Generation’s Consolidated Statements of Operations and Comprehensive Income. Generation’s net income in 2006 and 2005 reflects a gain on the sale of discontinued operations of $4 million and $19 million (both after tax), respectively. See Notes 2 and 3 of the Combined Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe as discontinued operations.

The income from discontinued operations decreased by $15 million for 2006 compared to 2005 primarily due to the gain on the sale of Sithe in the first quarter of 2005 partially offset by an adjustment to the gain on the sale of Sithe in the second quarter of 2006 as a result of the expiration of certain tax indemnifications, accrued interest and collections on receivables arising from the sale of Sithe that had been fully reserved.

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. See Note 13 of the Combined Notes to Consolidated Financial Statements for further discussion of the adoption of FIN 47.

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Results of Operations—ComEd

	2006			2005			Favorable (unfavorable) variance
Operating revenues	$	6,101		$	6,264		$	(163	)
Operating expenses
Purchased power		3,292			3,520			228
Operating and maintenance		745			833			88
Impairment of goodwill		776			1,207			431
Depreciation and amortization		430			413			(17	)
Taxes other than income		303			303			—
Total operating expense		5,546			6,276			730
Operating income (loss)		555			(12	)		567
Other income and deductions
Interest expense, net		(308	)		(291	)		(17	)
Equity in losses of unconsolidated affiliates		(10	)		(14	)		4
Other, net		96			4			92
Total other income and deductions		(222	)		(301	)		79
Income (loss) before income taxes and cumulative effect of a change in accounting principle		333			(313	)		646
Income taxes		445			363			(82	)
Loss before cumulative effect of a change in accounting principles		(112	)		(676	)		564
Cumulative effect of change in accounting principle		—			(9	)		9
Net loss	$	(112	)	$	(685	)	$	573

Net Loss. ComEd’s decreased net loss in 2006 compared to 2005 was driven by a smaller impairment of goodwill in 2006, lower purchased power expense and one-time benefits associated with reversing previously incurred expenses as a result of the July 2006 and December 2006 ICC rate orders as more fully described below, partially offset by lower operating revenues.

Operating Revenues. The changes in operating revenues for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
Weather	$	(226	)
Customer choice		(67	)
Volume		84
Rate changes and mix		23
Retail revenue		(186	)
Wholesale and miscellaneous revenues		28
Mark-to-market contracts		(5	)
Other revenues		23
Decrease in operating revenues	$	(163	)

Weather. Revenues were lower due to unfavorable weather conditions in 2006 compared to 2005. The demand for electricity is affected by weather conditions. Very warm weather in summer months

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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 20% and 8% lower, respectively, than the prior year.

Customer choice. All ComEd customers have the choice to purchase energy from a competitive electric generation 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, 2006, one competitive electric generation supplier had been granted approval to serve residential customers in the ComEd service territory. However, they are not currently supplying electricity to any residential customers.

For 2006 and 2005, 23% and 21%, respectively, of energy delivered to ComEd’s retail customers was provided by competitive electric generation suppliers. Most of the customers previously receiving energy under the PPO are now electing either to buy their power from a competitive electric generation supplier or from ComEd under bundled rates.

	2006		2005
Retail customers purchasing energy from a competitive electric generation supplier:
Volume (GWhs) (a)	20,787		19,310
Percentage of total retail deliveries	23	%	21	%
Retail customers purchasing energy from a competitive electric generation supplier or the ComEd PPO:
Number of customers at period end	20,300		21,300
Percentage of total retail customers	(b	)	(b	)
Volume (GWhs) (a)	25,521		30,905
Percentage of total retail deliveries	28	%	33	%

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

(b) Less than one percent.

Volume. Revenues were higher in 2006 compared to 2005 due primarily to an increase in deliveries, excluding the effects of weather, due to an increased number of customers.

Rate changes and mix. The increase in revenue related to rate and mix changes represents differences in year-over-year consumption between various customer classes offset by a decline in the CTC paid by customers of competitive electric generation suppliers due to the increase in market energy prices. The average rate paid by various customers is dependent on the amount and time of day that the power is consumed. Changes in customer consumption patterns, including increased usage, can result in an overall decrease in the average rate even though the tariff or rate schedule remains unchanged. Under current Illinois law, no CTCs will be collected after 2006. Starting in January 2007, ComEd began collecting revenues consistent with the approved ICC orders in the Procurement Case and the Rate Case. See Note 4 of the Combined Notes to the Consolidated Financial Statements for more information.

Wholesale and miscellaneous revenues. The wholesale and miscellaneous revenues increase primarily reflects an increase in transmission revenue reflecting increased peak and kWh load within the ComEd service territory.

Mark-to-market contracts. Mark-to-market contracts primarily reflect a mark-to-market loss associated with one wholesale contract that had previously been recorded as a normal sale under SFAS No. 133 in 2005. This contract expires in December 2007.

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Purchased Power Expense. The changes in purchased power expense for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
Prices	$	(135	)
Weather		(111	)
Customer choice		(56	)
PJM transmission		(6	)
Volume		42
SECA rates		38
Decrease in purchased power expense	$	(228	)

Prices. Purchased power decreased due to the decrease in contracted energy prices under the PPA that ComEd had with Generation. The PPA contract was entered into in March 2004 and reflected forward power prices in existence at that time. The PPA terminated at the end of 2006 and was replaced with the reverse-auction process in 2007, which was approved by the ICC. See Note 4 of the Combined Notes to Consolidated Financial Statements for more information on the reverse-auction process.

Weather. The decrease in purchased power expense attributable to weather was due to unfavorable weather conditions in the ComEd service territory relative to the prior year.

Customer choice. The decrease in purchased power expense from customer choice was primarily due to more ComEd non-residential customers electing to purchase energy from a competitive electric generation supplier.

PJM transmission. The decrease in PJM transmission expense reflects a decrease in ancillary charges, partially offset by increased peak demand and consumption by ComEd-supplied customers.

Volume. The amount of purchased power attributable to volume increased as a result of increased usage by ComEd-supplied customers on a weather-normalized basis versus the same period in 2005.

SECA rates. Effective December 1, 2004, PJM became obligated to pay SECA collections to ComEd and ComEd became obligated to pay SECA charges. These charges were being collected subject to refund as they are being disputed. As a result of current events related to SECA disputes, during the first quarter of 2006, ComEd increased its reserve for amounts to be refunded. ComEd recorded SECA collections and payments on a net basis through purchased power expense. As ComEd was a net collector of SECA charges, the 2005 purchased power expense, which reflected a full year of SECA collections, was lower than 2006, which reflected only three months of SECA collections, due to the expiration of SECA charges on March 31, 2006. See Note 4 of the Combined Notes to Consolidated Financial Statements for more information on the SECA rates.

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Operating and Maintenance Expense. The changes in operating and maintenance expense for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
ICC rate order (a)	$	(201	)
Fringe benefits (b)		43
Severance-related expenses		17
Wages and salaries		17
Customers’ Affordable Reliable Energy (CARE) program (c)		9
Environmental costs		5
Rent and lease expense		5
Storm costs		4
PSEG merger integration costs		2
Other		11
Decrease in operating and maintenance expense	$	(88	)

(a) As a result of the July 2006 ICC rate order and the December 2006 ICC order on rehearing, ComEd recorded one-time benefits associated with reversing previously incurred expenses, including MGP costs, severance costs and procurement case costs. See Notes 4 and 18 of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Reflects increases in various fringe benefits, including increased stock-based compensation expense of $24 million primarily due to the adoption of SFAS No. 123-R on January 1, 2006 and increased pension and other postretirement benefits costs of $14 million.

(c) See Note 4 of the Combined Notes to the Consolidated Financial Statements for additional information.

Impairment of Goodwill. ComEd performs an assessment of goodwill for impairment at least annually, or more frequently, if events or circumstances indicate that goodwill might be impaired. The assessment compares the carrying value of goodwill to the estimated fair value of goodwill as of a point in time. The estimated fair value incorporates management’s assessment of current events and expected future cash flows. See Note 8 of the Combined Notes to the Consolidated Financial Statements for additional information. During the third quarter of 2006, ComEd completed an interim assessment of goodwill for impairment purposes to reflect the adverse affects of the ICC’s July 2006 rate order. The test indicated that ComEd’s goodwill was impaired and a charge of $776 million was recorded. ComEd’s 2006 annual goodwill impairment assessment (performed in the fourth quarter) resulted in no additional impairment. After reflecting the impairment, ComEd had approximately $2.7 billion of remaining goodwill as of December 31, 2006.

During the fourth quarter of 2005, ComEd completed the annually required assessment of goodwill for impairment purposes. 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 PPA 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.

Depreciation and Amortization Expense. The changes in depreciation and amortization expense for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
Depreciation expense associated with higher plant balances	$	12
Other amortization expense		5
Increase in depreciation and amortization expense	$	17

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In 2007, ComEd’s amortization will reflect the elimination of the recoverable transition costs regulatory asset and the initial amortization of the various regulatory assets authorized by the ICC in its July and December 2006 orders. See Notes 4, 18 and 19 of the Combined Notes of the Consolidated Financial statements for more information.

Taxes Other Than Income. Taxes other than income remained constant in 2006 compared to 2005.

Interest Expense, Net. The increase in interest expense, net in 2006 compared to 2005 primarily resulted from higher debt balances and higher interest rates. In 2007, ComEd’s interest expense, net will reflect the initial amortization of the regulatory asset related to the early debt retirement costs authorized by the ICC in its July 2006 order. See Notes 4, 18 and 19 of the Combined Notes of the Consolidated Financial statements for more information.

Other, Net. The changes in other, net for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
ICC rate order (a)	$	87
Loss on settlement of 2005 cash-flow swaps		15
Sale of receivable in 2005		(3	)
Loss on disposition of assets and investments, net		(3	)
Other		(4	)
Increase in other, net	$	92

(a) As a result of the July 2006 ICC rate order, ComEd recorded a one-time benefit associated with reversing previously incurred expenses to retire debt early. See Notes 4, 18 and 19 of the Combined Notes to the Consolidated Financial Statements for additional information.

Income Taxes. The effective income tax rate was 133.6% and (116.0)% for 2006 and 2005, respectively. The goodwill impairment charges increased the effective income tax rate by 81.6% in 2006 and decreased the effective income tax rate by 135.0% in 2005. See Note 12 of the Combined 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 13 of the Combined 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)	2006	2005	Variance		% Change
Full service (a)
Residential	28,330	30,042	(1,712	)	(5.7	)%
Small commercial & industrial	24,122	21,378	2,744		12.8	%
Large commercial & industrial	10,336	7,904	2,432		30.8	%
Public authorities & electric railroads	2,254	2,133	121		5.7	%
Total full service	65,042	61,457	3,585		5.8	%
PPO
Small commercial & industrial	2,475	5,591	(3,116	)	(55.7	)%
Large commercial & industrial	2,259	6,004	(3,745	)	(62.4	)%
	4,734	11,595	(6,861	)	(59.2	)%
Delivery only (b)
Small commercial & industrial	5,505	5,677	(172	)	(3.0	)%
Large commercial & industrial	15,282	13,633	1,649		12.1	%
	20,787	19,310	1,477		7.6	%
Total PPO and delivery only	25,521	30,905	(5,384	)	(17.4	)%
Total retail deliveries	90,563	92,362	(1,799	)	(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 a competitive electric generation supplier.

Electric Revenue	2006			2005		Variance			% Change
Full service (a)
Residential	$	2,453		$	2,584	$	(131	)	(5.1	)%
Small commercial & industrial		1,882			1,671		211		12.6	%
Large commercial & industrial		563			408		155		38.0	%
Public authorities & electric railroads		137			132		5		3.8	%
Total full service		5,035			4,795		240		5.0	%
PPO (b)
Small commercial & industrial		178			385		(207	)	(53.8	)%
Large commercial & industrial		137			345		(208	)	(60.3	)%
		315			730		(415	)	(56.8	)%
Delivery only (c)
Small commercial & industrial		85			95		(10	)	(10.5	)%
Large commercial & industrial		155			156		(1	)	(0.6	)%
		240			251		(11	)	(4.4	)%
Total PPO and delivery only		555			981		(426	)	(43.4	)%
Total electric retail revenues		5,590			5,776		(186	)	(3.2	)%
Wholesale and miscellaneous revenue (d)		516			488		28		5.7	%
Mark-to-market contracts		(5	)		—		(5	)	n.m.
Total operating revenues	$	6,101		$	6,264	$	(163	)	(2.6	)%

(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.

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(b) Revenues from customers choosing the PPO include an energy charge at market rates, transmission and distribution charges, and a CTC through December 2006.

(c) Delivery only revenues reflect revenue under tariff rates from customers electing to receive electricity from a competitive electric generation supplier, which includes a distribution charge and a CTC through December 2006.

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

n.m. Not meaningful

Results of Operations—PECO

	2006			2005			Favorable (unfavorable) variance
Operating revenues	$	5,168		$	4,910		$	258
Operating expenses
Purchased power and fuel		2,702			2,515			(187	)
Operating and maintenance		628			549			(79	)
Depreciation and amortization		710			566			(144	)
Taxes other than income		262			231			(31	)
Total operating expense		4,302			3,861			(441	)
Operating income		866			1,049			(183	)
Other income and deductions
Interest expense, net		(266	)		(279	)		13
Equity in losses of unconsolidated affiliates		(9	)		(16	)		7
Other, net		30			13			17
Total other income and deductions		(245	)		(282	)		37
Income before income taxes and cumulative effect of a change in accounting principle		621			767			(146	)
Income taxes		180			247			67
Income before cumulative effect of a change in accounting principle		441			520			(79	)
Cumulative effect of a change in accounting principle		—			(3	)		3
Net income		441			517			(76	)
Preferred stock dividends		4			4			—
Net income on common stock	$	437		$	513		$	(76	)

Net Income. PECO’s net income in 2006 decreased primarily due to higher CTC amortization and higher operating and maintenance expense, which reflected higher storm costs. Partially offsetting these factors were higher revenues, net of purchased power and fuel expense. Higher net revenues reflected certain authorized electric rate increases, including a scheduled CTC rate increase, partially offset by lower net electric and gas revenues as a result of unfavorable weather relative to the prior year. The increases in CTC amortization expense and CTC rates were in accordance with PECO’s 1998 restructuring settlement with the PAPUC. The increase in CTC amortization expense exceeded the increase in CTC revenues.

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Operating Revenues. The changes in PECO’s operating revenues for 2006 compared to 2005 consisted of the following:

	Electric			Gas			Total increase (decrease)
Rate increases	$	237		$	127		$	364
Customer choice		62			—			62
Unbilled revenue—change in estimate		35			—			35
Volume		20			(10	)		10
Weather		(91	)		(130	)		(221	)
Other rate changes and mix		(10	)		—			(10	)
Retail revenue		253			(13	)		240
Wholesale and miscellaneous revenues		26			(8	)		18
Increase (decrease) in operating revenues	$	279		$	(21	)	$	258

Rate increases. The increase in electric revenues attributable to electric rate increases reflects scheduled CTC and generation rate increases in accordance with PECO’s 1998 restructuring settlement with the PAPUC and the elimination of the aggregate $200 million electric distribution rate reductions over the period January 1, 2002 through December 31, 2005 (approximately $40 million in 2005) related to the PAPUC’s approval of the merger between PECO and ComEd. On January 1, 2007, a scheduled electric generation rate increase took effect, which represents the last scheduled rate increase through 2010 under PECO’s 1998 restructuring settlement. This rate increase will not affect operating income as PECO will incur corresponding and offsetting purchased power expenses under its PPA with Generation. The increase in gas revenues was due to net increases in rates through PAPUC-approved quarterly changes to the purchased gas adjustment clause. The average purchased gas cost rate per million cubic feet in effect for the twelve months ended December 31, 2006 was 30% higher than the average rate for the same period in 2005. While PECO’s average purchased gas cost rate was higher in 2006 compared to 2005, quarterly changes to purchased gas cost rates since March 1, 2006 have resulted in decreases to the rates, with the September 1, 2006 and December 1, 2006 rate decreases resulting in lower rates in 2006 compared to comparable periods in 2005. This trend will continue into the first quarter of 2007, during the peak of PECO’s winter heating season, as first quarter 2007 rates will be significantly lower than first quarter 2006 rates.

Customer choice. All PECO customers have the choice to purchase energy from a competitive electric generation supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. PECO’s 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.

For 2006 and 2005, 2% and 5%, respectively, of energy delivered to PECO’s retail customers was provided by competitive electric generation suppliers.

	2006		2005
Retail customers purchasing energy from a competitive electric generation supplier:
Number of customers at period end	34,400		44,500
Percentage of total retail customers	2	%	3	%
Volume (GWhs) (a)	767		2,094
Percentage of total retail deliveries	2	%	5	%

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

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The increase in electric retail revenue associated with customer choice reflected customers from all customer classes returning to PECO as their electric supplier as a result of rising wholesale energy prices and a number of competitive electric generation suppliers exiting the market during 2005 and 2006.

Unbilled revenue—change in estimate. In the fourth quarter of 2006, PECO recorded a $35 million increase to unbilled electric revenues associated with a change in estimate in the amount of revenue recognized, although unbilled, at the end of 2006. As discussed under Critical Accounting Policies and Estimates, the nature of the unbilled revenue calculation is inherently an estimation process. As a result of Exelon’s integration efforts associated with its then-pending merger with PSEG, analyses received from a third-party consultant, and PECO’s implementation of a new customer information management system in the fourth quarter 2006, PECO received new information with which to better analyze the data underlying its unbilled revenue calculation. This amount is partially offset by a $14 million increase in purchased power expense as noted below.

Volume. The increase in electric revenues was primarily as a result of higher delivery volume, exclusive of the effects of weather and customer choice, primarily due to an increased number of customers in the residential and small commercial and industrial 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 lower due to unfavorable weather conditions in PECO’s service territory, where heating and cooling degree days were 18% and 15% lower, respectively, than the prior year.

Other rate changes and mix. The decrease in electric revenues attributable to other rate changes and mix was primarily due to increased large commercial and industrial sales, which are billed at lower rates relative to other customer classes, and lower rates for certain large commercial and industrial customers whose rates reflect wholesale energy prices, which were lower in the latter part of 2006 relative to 2005.

Wholesale and miscellaneous revenues. The increase in electric revenues was primarily due to increased PJM transmission revenue and increased sales of energy into the PJM spot market. If PECO’s energy needs are less than the daily amount scheduled, the excess is sold into the PJM spot market. Revenues from these sales are reflected as adjustments to the billings under PECO’s PPA with Generation. The decrease in gas revenues was due to decreased off-system sales.

Purchased Power and Fuel Expense. The changes in PECO’s purchased power and fuel expense for 2006 compared to 2005 consisted of the following:

	Electric			Gas			Total increase (decrease)
Prices	$	94		$	127		$	221
Customer choice		62			—			62
PJM transmission		31			—			31
Unbilled revenue—change in estimate		14			—			14
Weather		(39	)		(107	)		(146	)
Volume		4			(13	)		(9	)
Other		20			(6	)		14
Increase in purchased power and fuel expense	$	186		$	1		$	187

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Prices. PECO’s purchased power expense increased $87 million corresponding to the increase in electric revenues which was attributable to the scheduled PAPUC-approved generation rate increase. In addition, PECO’s purchased power expense increased $7 million due to a change in the mix of average pricing related to its PPA with Generation. Fuel expense for gas increased due to higher average gas prices. See “Operating Revenues” above.

Customer choice. The increase in purchased power expense from customer choice was primarily due to customers from all customer classes returning to PECO as their electric supplier, primarily as a result of rising wholesale energy prices and a number of competitive electric generation suppliers exiting the market during 2005 and 2006.

PJM transmission. The increase in PJM transmission expense reflects increased peak demand and consumption by PECO-supplied customers due to load growth as well as an increase in PECO-supplied customers driven by more customers choosing PECO for supply due to competitive electric generation suppliers’ higher market prices.

Unbilled revenue—change in estimate. In the fourth quarter of 2006, PECO recorded a $14 million increase to purchased power associated with a change in estimate for unbilled electric revenue as the energy component of the estimate change is passed onto Generation.

Weather. The decrease in purchased power and fuel expense attributable to weather was primarily due to lower demand as a result of unfavorable weather conditions in the PECO service territory relative to the prior year.

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

Other. The increase in electric purchased power expense was primarily due to increased energy purchases in the PJM spot market. If PECO’s energy needs are greater than the daily amount scheduled, the shortfall is secured through purchases in the PJM spot market. These additional costs are reflected as adjustments to the billings under PECO’s PPA with Generation. The decrease in gas fuel expense was related to decreased off-system sales.

Operating and Maintenance Expense. The changes in operating and maintenance expense for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
Storm costs	$	36
Contractors (a)		14
Allowance for uncollectible accounts (b)		13
Fringe benefits (c)		11
Severance-related expenses		6
PSEG merger integration costs		2
Injuries and damages		(6	)
Environmental reserve (d)		(4	)
Other		7
Increase in operating and maintenance expense	$	79

(a) Reflects higher professional fees, including $9 million associated with tax consulting, and various other increases. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding tax consulting fees.

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(b) Reflects the following factors, all of which increased expense in 2006 as compared to 2005: (i) higher average accounts receivable balances in 2006 compared to 2005 resulting from increased revenues; (ii) changes in PAPUC-approved regulations related to customer payment terms; and (iii) an increase in the number of low-income customers participating in customer assistance programs, which allow for the forgiveness of certain receivables.

(c) Reflects increased stock-based compensation expense of $11 million primarily due to the adoption of SFAS No. 123-R on January 1, 2006.

(d) Represents a settlement related to one Superfund site in the first quarter of 2006. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

Depreciation and Amortization Expense. The changes in depreciation and amortization expense for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
CTC amortization (a)	$	146
Accelerated amortization of PECO billing system (b)		(4	)
Other depreciation and amortization expense		2
Increase in depreciation and amortization expense	$	144

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

(b) In January 2005, as part of a broader systems strategy at PECO associated with the proposed 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 required the accelerated amortization of PECO’s existing system through 2006 and the recognition of additional amortization expense of $13 million and $9 million in 2005 and 2006, respectively. The new system was implemented in the fourth quarter 2006.

Taxes Other Than Income. The changes in taxes other than income for 2006 compared to 2005 consisted of the following:

	Increase (decrease)
Taxes on utility revenues (a)	$	14
State franchise tax adjustments in 2006 and 2005 (b)		10
Real estate tax adjustment in 2005 (c)		6
Sales and use tax adjustments in 2006 and 2005		(2	)
Other		3
Increase in taxes other than income	$	31

(a) 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.

(b) Represents the reduction of tax accruals in 2006 of $7 million following settlements related to prior year tax assessments and the $17 million reduction of an accrual in 2005 related to prior years.

(c) Represents the reduction of a real estate tax accrual in 2005 following settlements related to prior year tax assessments.

Interest Expense, Net. The decrease in interest expense, net for 2006 compared to 2005 was primarily due to scheduled payments on long-term debt owed to PECO Energy Transition Trust (PETT), partially offset by an increase in interest expense associated with the September 2006 issuance of $300 million First Mortgage Bonds, higher interest rates on variable rate long-term debt and an increased amount of commercial paper outstanding at higher rates.

Other, Net. The increase in other, net for 2006 compared to 2005 was primarily due to interest income associated with an investment tax credit refund of $11 million and interest income associated with a research and development credit refund of $10 million in 2006. See Note 19 of the Combined Notes to the Consolidated Financial Statements for further details of the components of other, net. See Note 18 of the Combined Notes to the Consolidated Financial Statement for additional information regarding the investment tax credit and research and development credit refunds.

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

Income Taxes. PECO’s effective income tax rate was 29.0% for 2006 compared to 32.2% for 2005. The lower effective tax rate in 2006 reflects investment tax credit and research and development credit refunds in 2006. See Note 12 of the Combined 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 13 of the Combined 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)	2006	2005	Variance		% Change
Full service (a)
Residential	12,796	13,135	(339	)	(2.6	)%
Small commercial & industrial	7,818	7,263	555		7.6	%
Large commercial & industrial	15,898	15,205	693		4.6	%
Public authorities & electric railroads	906	962	(56	)	(5.8	)%
Total full service	37,418	36,565	853		2.3	%
Delivery only (b)
Residential	61	334	(273	)	(81.7	)%
Small commercial & industrial	671	1,257	(586	)	(46.6	)%
Large commercial & industrial	35	503	(468	)	(93.0	)%
Total delivery only	767	2,094	(1,327	)	(63.4	)%
Total retail deliveries	38,185	38,659	(474	)	(1.2	)%

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

(b) Delivery only service reflects customers receiving electric generation service from a competitive electric generation supplier.

Electric Revenue	2006		2005		Variance			% Change
Full service (a)
Residential	$	1,780	$	1,705	$	75		4.4	%
Small commercial & industrial		943		818		125		15.3	%
Large commercial & industrial		1,286		1,173		113		9.6	%
Public authorities & electric railroads		83		84		(1	)	(1.2	)%
Total full service		4,092		3,780		312		8.3	%
Delivery only (b)
Residential		5		25		(20	)	(80.0	)%
Small commercial & industrial		36		63		(27	)	(42.9	)%
Large commercial & industrial		1		13		(12	)	(92.3	)%
Total delivery only		42		101		(59	)	(58.4	)%
Total electric retail revenues		4,134		3,881		253		6.5	%
Wholesale and miscellaneous revenue (c)		238		212		26		12.3	%
Total electric and other revenue	$	4,372	$	4,093	$	279		6.8	%

(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.

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

(c) Wholesale and 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))	2006		2005		Variance			% Change
Retail sales		50,578		59,751		(9,173	)	(15.4	)%
Transportation		25,527		25,310		217		0.9	%
Total		76,105		85,061		(8,956	)	(10.5	)%
Revenue	2006		2005		Variance			% Change
Retail sales	$	770	$	783	$	(13	)	(1.7	)%
Transportation		16		16		—		—	%
Resales and other		10		18		(8	)	(44.4	)%
Total gas revenue	$	796	$	817	$	(21	)	(2.6	)%

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

Results of Operations–Exelon

	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	15,357		$	14,133		$	1,224
Operating expenses
Purchased power and fuel expense		5,670			4,929			(741	)
Operating and maintenance expense		3,694			3,700			6
Impairment of goodwill		1,207			—			(1,207	)
Depreciation and amortization		1,334			1,295			(39	)
Taxes other than income		728			710			(18	)
Total operating expenses		12,633			10,634			(1,999	)
Operating income		2,724			3,499			(775	)
Other income and deductions
Interest expense		(513	)		(471	)		(42	)
Interest expense to affiliates, net		(316	)		(357	)		41
Equity in losses of unconsolidated affiliates		(134	)		(154	)		20
Other, net		134			60			74
Total 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 before minority interest		951			1,864			(913	)
Minority interest		—			6			(6	)
Income from continuing operations		951			1,870			(919	)
Income 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	)

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Net Income. Net income for 2005 reflects an impairment charge of $1.2 billion 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 the Combined 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 PPA 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.

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. During 2005, in connection with the annually required assessment of goodwill for impairment, ComEd recorded a $1.2 billion charge.

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.

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Effective Income Tax Rate. The effective income tax rate from continuing operations was 49.8% for 2005 compared to 27.7% for 2004. The goodwill impairment charge increased the effective income tax rate from continuing operations by 22.3% for 2005. See Note 12 of the Combined 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 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 Operations. See Notes 2 and 3 of the Combined 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 13 of the Combined Notes to Consolidated Financial Statements for further discussion of the consolidation of Sithe and the adoption of FIN 47, respectively.

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
Generation	$	1,109		$	657	$	452
ComEd		(676	)		676		(1,352	)
PECO		520			455		65
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
Generation	$	1,128		$	641	$	487
ComEd		(676	)		676		(1,352	)
PECO		520			455		65
Other (a)		(7	)		69		(76	)
Total	$	965		$	1,841	$	(876	)

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(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
Generation	$	1,098		$	673	$	425
ComEd		(685	)		676		(1,361	)
PECO		517			455		62
Other (a)		(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.

Results of Operations—Generation

	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	9,046		$	7,703		$	1,343
Operating expenses
Purchased power and fuel		4,482			4,011			(471	)
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		—			(16	)		16
Gain on disposal of discontinued operations		19			—			19
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

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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 PPA 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.

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, operating service agreements 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 competitive electric generation 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.

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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 PPA 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.

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	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, including Salem, which is operated by PSEG Nuclear.

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

	Price		Volume			Increase (Decrease)
Purchased power costs	$	654	$	(327	)	$	327
Generation costs		198		16			214
Fuel resale costs		149		(2	)		147
Sale of Boston Generating		n.m.		n.m.			(226	)
Mark-to-market		n.m.		n.m.			9
Increase in purchased power and fuel expense						$	471

n.m. Not meaningful

Purchased Power Costs. Purchased power costs include all costs associated with the procurement of electricity (i.e., capacity, energy and fuel costs). Generation experienced overall higher realized prices for purchased power in 2005 compared to 2004, resulting in a $654 million increase. This was offset by a decrease of $327 million due to lower volumes of purchased power in the market as a result of more demand from affiliates.

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Generation Costs. Generation costs include fuel cost for internally generated energy. Generation experienced overall higher generation costs for 2005 compared to 2004 due to overall energy market conditions resulting in higher prices for raw materials (e.g., oil, natural gas and coal) used in the production of electricity. Additionally, there was an increase of $16 million related to higher nuclear and fossil generation need to meet affiliates’ demand.

Fuel Resale Costs. Fuel resale costs include retail gas purchase and wholesale fossil fuel expenses. The changes in Generation’s fuel resale costs in 2005 as compared to 2004 consisted of overall higher realized gas prices, offset by a $2 million volume decrease in the gas retail business.

Sale of 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.

Mark-to-market. Mark-to-market losses on power derivative activities were $12 million for 2005 compared to losses of $3 million for 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 was 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

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

Generation’s nuclear fleet capacity factor was the same in 2005 as 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 was 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 the Combined 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.

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

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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 the Combined 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 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 Operations. See Notes 2 and 3 of the Combined 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 13 of the Combined Notes to Consolidated Financial Statements for further discussion of the consolidation of Sithe and the adoption of FIN 47, respectively.

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, net		(291	)		(349	)		58
Equity in losses of unconsolidated affiliates		(14	)		(19	)		5
Net loss on extinguishment of long-term debt		—			(130	)		130
Other, net		4			14			(10	)
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	)

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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	)
Miscellaneous revenues		13
Other revenues		43
Increase in operating revenues	$	461

Weather. Revenues were higher due to favorable weather conditions in 2005 compared to 2004. The demand for electricity is affected by weather conditions. In ComEd’s service territory, cooling and heating degree days were 90% and 1% higher, respectively, than the prior year.

Customer choice. All ComEd customers have the choice to purchase energy from a competitive electric generation 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 competitive electric generation supplier was approved to serve residential customers in the ComEd service territory. However, they are not currently supplying electricity to any residential customers.

For 2005 and 2004, 33% and 35% of energy delivered to ComEd’s retail customers was provided by competitive electric generation suppliers or under the PPO.

	2005		2004
Retail customers purchasing energy from a competitive electric generation supplier:
Volume (GWhs) (a)	19,310		20,939
Percentage of total retail deliveries	21	%	24	%
Retail customers purchasing energy from a competitive electric generation supplier or the ComEd PPO:
Number of customers at period end	21,300		22,200
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 was 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.

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

T&O / SECA rates. Revenues decreased 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 4 of the Combined Notes to Consolidated Financial Statements for more information on T&O / SECA rates.

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 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 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 increase in purchased power expense from customer choice was primarily due to fewer ComEd non-residential customers electing to purchase energy from a competitive electric generation supplier.

PJM. The 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.

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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 4 of the Combined Notes to Consolidated Financial Statements for more information on T&O /SECA rates.

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 14 of the Combined 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 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 PPA 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, Net. The reduction in interest expense, net 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 Transitional Funding Trust, partially offset by a $16 million decrease in interest income on the long-term receivable from UII, LLC as a result of this receivable being repaid in late 2004.

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 included a $15 million loss on settlement of cash-flow swaps in 2005. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information.

Income Taxes. The effective income tax rate was (116.0)% and 40.3% for 2005 and 2004, respectively. The goodwill impairment charge decreased the effective income tax rate by 135.0% in 2005. See Note 12 of the Combined 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 13 of the Combined 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 a competitive electric generation supplier.

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.

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(c) Delivery only revenues reflect revenue under tariff rates from customers electing to receive electricity from a competitive electric generation 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 competitive electric generation 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.

Results of Operations—PECO

	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	4,910		$	4,487		$	423
Operating expenses
Purchased power and fuel		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, net		(279	)		(303	)		24
Equity in losses of unconsolidated affiliates		(16	)		(25	)		9
Other, net		13			18			(5	)
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. All PECO customers have the choice to purchase energy from a competitive electric generation supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. PECO’s 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.

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

	2005		2004
Retail customers purchasing energy from a competitive electric generation 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 competitive electric generation 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

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Expense” below. The elimination of T&O revenues and inclusion of SECA revenues had a minimal 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 4 of the Combined 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 4 of the Combined Notes to Consolidated Financial Statements for more information on T&O and 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 (a)	$	37
Accelerated amortization of PECO billing system (b)		13
Depreciation expense(c)		3
Other amortization expense		(5	)
Increase in depreciation and amortization expense	$	48

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

(b) In January 2005, as part of a broader systems strategy at PECO associated with the proposed 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 $9 million in 2005 and 2006, respectively.

(c) 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	)

(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 18 of the Combined 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.

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Interest Expense, Net. The reduction in interest expense, net 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 lower effective tax rate reflects a state income tax benefit recorded as a result of the favorable settlement of a 2000 Pennsylvania corporate net income tax audit. See Note 12 of the Combined 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 13 of the Combined 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 a competitive electric generation 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	%
Wholesale and 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 a competitive electric generation supplier, which includes a distribution charge and a CTC.

(c) Wholesale and 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	%

Liquidity and Capital Resources

The Registrants’ businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from operations. When necessary, the Registrants obtain funds from external sources in the capital markets and through bank borrowings. The Registrants’ access to external financing on reasonable terms depends on their credit ratings and current business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, Exelon, Generation, ComEd and PECO have access to revolving credit facilities with aggregate bank commitments of $1 billion, $5 billion, $1 billion and $600 million, respectively, that they currently utilize to support their commercial paper programs and to issue letters of credit. See the “Credit Issues” section of “Liquidity and Capital Resources” for further discussion.

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The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on construction projects that have a long-term return on investment. Additionally, ComEd and PECO operate in rate-regulated environments 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, each of Exelon’s, ComEd’s and PECO’s working capital, defined as current assets less current liabilities, is in a net deficit position. ComEd intends to refinance maturing long-term debt during 2007. To manage cash flows as more fully described below, ComEd did not pay a dividend during 2006. Future acquisitions that Exelon may undertake may involve external debt financing or the issuance of additional Exelon common stock.

Cash Flows from Operating Activities

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 as well as to obtain collections from customers. 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 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, future regulatory proceedings with respect to their rates and their ability to achieve operating cost reductions. See Note 4 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.

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 11 of the Combined 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. 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 is below ComEd’s cost to procure and deliver electricity, there may be potential material adverse consequences to ComEd and, possibly, Exelon. The ICC approved a “cap and deferral” program, proposed by ComEd, to ease the impact of the expected increase in rates on residential customers. The cap and deferral program, generally speaking, will limit the procurement costs that ComEd can pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years. See Note 4 of the Combined Notes to the Consolidated Financial Statements for further detail on the procurement case.

Generation’s sales to counterparties other than ComEd and PECO will increase due to the expiration of the PPA with ComEd at the end of 2006. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. Under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, beginning in 2007, collateral postings will be one-sided from Generation only. That is, if market prices fall below ComEd’s or Ameren’s contracted price levels, ComEd or Ameren are not required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation is required to post collateral. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information regarding Generation’s collateral policy.

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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, to which the IRS has objected. As discussed in Note 12 of the Combined Notes to the Consolidated Financial Statements, this deferred tax obligation is significant.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations:

	2006			2005		Variance
Net income	$	1,592		$   923		$	669
Add (subtract):
Non-cash operating activities (a)		3,213		4,102			(889	)
Income taxes		69		138			(69	)
Changes in working capital and other noncurrent assets and liabilities (b)		141		(791	)		932
Pension contributions and postretirement healthcare benefit payments, net		(180	)	(2,225	)		2,045
Net cash flows provided by operations	$	4,835		$2,147		$	2,688

(a) Includes depreciation, amortization and accretion, deferred income taxes, provision for uncollectible accounts, equity in earnings of unconsolidated affiliates, pension and other postretirement benefits expense, other decommissioning-related activities, cumulative effect of a change in accounting principle, impairment charges and other non-cash items.

(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 increase in cash flows from operations during 2006 was primarily the result of $2 billion of discretionary contributions to Exelon’s pension plans during 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, Generation, ComEd and PECO contributed $844 million, $803 million, and $109 million, respectively. The Generation contribution was primarily funded by capital contributions from Exelon and included $2 million from internally generated funds. ComEd’s and PECO’s contributions were funded by capital contributions from Exelon.

Cash flows provided by operations for 2006 and 2005 by registrant were as follows:

	2006		2005
Exelon	$	4,835	$	2,147
Generation		2,550		972
ComEd		987		247
PECO		1,017		704

Excluding the March 2005 discretionary pension contributions discussed above, changes in the Registrants’ cash flows from operations were generally consistent with changes in their results of operations, as adjusted by changes in working capital in the normal course of business.

In addition to the items mentioned in “Results of Operations” and the discretionary pension contributions discussed above, significant operating cash flow impacts for Generation and ComEd for 2006 and 2005 were as follows:

Generation

• At December 31, 2006, 2005 and 2004, Generation had accounts receivable from ComEd under the PPA of $197 million, $242 million and $189 million, respectively.

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• At December 31, 2006, 2005 and 2004, Generation had accounts receivable from PECO under the PPA of $153 million, $151 million and $125 million, respectively.

• During 2006, Generation had net collections of counterparty collateral of $431 million compared to $187 million of net disbursements of counterparty collateral in 2005. The increase in cash inflows from 2005 was primarily due to changes in collateral requirements resulting from the extension of letters of credit and changes in market prices relative to positions with counterparties.

• During 2006 and 2005, Generation had net payments of approximately $220 million and $165 million, respectively, primarily due to increased use of financial instruments to economically 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 the first quarter of 2006, Exelon remitted a $98 million payment to the IRS in connection with the settlement of the IRS’s challenge of the timing of the above-described deduction. This payment included $6 million of interest which was recognized as interest expense in the first quarter of 2006. Exelon received approximately $92 million on December 13, 2006 related to this same deduction in connection with the filing of its 2005 tax return.

ComEd

• At December 31, 2006, 2005 and 2004, ComEd had accrued payments to Generation under the PPA of $197 million, $242 million and $189 million, respectively.

• In 2005, ComEd settled $325 million of interest rate swaps that were designated as cash flow hedges for a loss of $15 million. This was recorded as a pre-tax charge to net income because the underlying transaction for which these interest rate swaps were entered into was no longer probable of occurring.

Cash Flows from Investing Activities

Cash flows used in investing activities for 2006 and 2005 by registrant were as follows:

	2006			2005
Exelon	$	(2,762	)	$	(2,487	)
Generation		(1,406	)		(1,294	)
ComEd		(894	)		(479	)
PECO		(332	)		(241	)

Capital expenditures by registrant and business segment for 2006 and projected amounts for 2007 are as follows:

	2006		2007
Generation (a)	$	1,109	$	1,353
ComEd		911		1,055
PECO		345		355
Other (b)		53		38
Total Exelon capital expenditures	$	2,418	$	2,801

(a) Includes nuclear fuel.

(b) Other primarily consists of corporate operations.

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Projected capital expenditures and other investments by the Registrants are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Generation. Generation’s capital expenditures for 2006 reflected additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages) and nuclear fuel. Generation anticipates that its capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon.

ComEd and PECO. Approximately 50% of the projected 2007 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. ComEd and PECO are continuing to evaluate their total capital spending requirements. ComEd and PECO anticipate that their capital expenditures will be funded by internally generated funds, borrowings and the issuance of debt or preferred securities.

Other significant investing activities for Exelon, Generation, ComEd and PECO for 2006 and 2005 were as follows:

Exelon

• Exelon contributed $92 million and $102 million to its investments in synthetic fuel-producing facilities during 2006 and 2005, respectively.

Generation

• During 2006, Generation made contributions to the Exelon intercompany money pool totaling $13 million.

• 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 its 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 the Combined Notes to the Consolidated Financial Statements for further discussion of the sale of Sithe.

ComEd

• As a result of its prior contributions to the Exelon intercompany money pool, $308 million was returned to ComEd during 2005.

PECO

• During 2006 and 2005, $8 million and $26 million, respectively, were returned to PECO as a result of its prior contributions to the Exelon intercompany money pool.

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Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for 2006 and 2005 by registrant were as follows:

	2006			2005
Exelon	$	(1,989	)	$	(19	)
Generation		(1,050	)		93
ComEd		(96	)		240
PECO		(693	)		(500	)

Debt. Debt activity for 2006 by registrant was as follows:

Registrant	Debt issued in 2006	Use of proceeds
ComEd	$325 million of First Mortgage 5.90% Bonds, Series 103, due March 15, 2036	Used to supplement working capital previously used to refinance amounts that ComEd used to repay bonds and notes.
ComEd	$300 million of First Mortgage 5.95% Bonds, Series 104, due August 15, 2016	Used to repay commercial paper and for other general corporate purposes.
ComEd	Additional $115 million of First Mortgage 5.95% Bonds, Series 104, due August 15, 2016	Used to repay bonds at maturity.
ComEd	$345 million of First Mortgage 5.40% Bonds, Series 105, due December 15, 2011	Used to repay borrowings under ComEd’s revolving credit agreement which had been used to repay bonds and to refinance notes.
PECO	$300 million of First Mortgage Bonds 5.95% Series, due October 1, 2036	Used to repay commercial paper and for other general corporate purposes.

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 $842 million, $803 million and $109 million by Generation, ComEd and PECO, respectively. To facilitate the contributions by Generation, ComEd and PECO, 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 the $2 billion term loan. During the second quarter of 2005, $200 million of the $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. See Note 11 of the Combined 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.

From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen their respective balance sheets.

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Generation and Peoples Calumet, LLC (Peoples Calumet), a subsidiary of Peoples Energy Corporation, were joint owners of Southeast Chicago Energy Project, LLC (SCEP), a 350-megawatt natural gas-fired, peaking electric power plant located in Chicago, Illinois, which began operation in 2002. In 2002, Generation and Peoples Calumet owned 70% and 30%, respectively, of SCEP. Generation reflected the third-party interest in this majority-owned investment as a long-term liability in its consolidated financial statements. Pursuant to the joint owners agreement, Generation was obligated to purchase Peoples Calumet’s 30% interest ratably over a 20-year period. On March 31, 2006, Generation entered into an agreement to accelerate the acquisition of Peoples Calumet’s interest in SCEP. This transaction closed on May 31, 2006. Under the agreement, Generation paid Peoples Calumet approximately $47 million for its remaining interest in SCEP. Generation financed this transaction using short-term debt and available cash.

Cash dividend payments and distributions in 2006 and 2005 by registrant were as follows:

	2006		2005
Exelon	$	1,071	$	1,070
Generation		609		857
ComEd		—		498
PECO		506		473

Exelon paid dividends of $267 million, $268 million, $268 million and $268 million on March 10, 2006, June 12, 2006, September 11, 2006 and December 11, 2006, respectively, to shareholders of record at the close of business on February 15, 2006, May 15, 2006, August 15, 2006 and November 15, 2006, respectively. On December 5, 2006, Exelon’s board of directors declared a quarterly dividend of $0.44 per share on Exelon’s common stock, which is payable on March 10, 2007 to shareholders of record at the end of the day on February 15, 2007. See “Dividends” section of ITEM 5 for a further discussion of Exelon’s dividend policy.

During 2006, ComEd did not pay any dividend. The decision by the ComEd Board of Directors not to declare a dividend was the result of several factors, including ComEd’s need for a rate increase to cover existing costs and anticipated levels of future capital expenditures as well as the continued uncertainty related to ComEd’s regulatory filings as discussed in Note 4 of the Combined Notes to Consolidated Financial Statements. ComEd’s Board of Directors will continue to assess ComEd’s ability to pay a dividend on a quarterly basis.

In 2003, Congress passed and President Bush signed into law the Jobs and Growth Tax Reconciliation Act, legislation which lowered the tax rate on capital gains and corporate dividends to 15% for most investors and to 5% for lower-income investors. Prior to enactment of this law, the maximum tax rate on dividend income was 38.6%. These provisions, which were originally scheduled to expire at the end of 2008, were extended to 2010 as part of the Tax Relief Reconciliation Act of 2005 passed in May 2006.

Intercompany Money Pool. Generation’s net borrowings from the Exelon intercompany money pool decreased $92 million and $191 million during 2006 and 2005, respectively. During 2006, ComEd repaid $140 million that it had borrowed from the Exelon intercompany money pool. ComEd’s net borrowings from the Exelon intercompany money pool increased $140 million during 2005. As of January 10, 2006, ComEd suspended participation in the intercompany money pool. PECO’s net borrowings from the Exelon intercompany money pool increased $45 million in 2006.

Commercial Paper and Notes Payable. During 2006, Exelon, Generation, ComEd and PECO repaid $685 million, $311 million, $399 million and $125 million, net, of commercial paper, respectively. During 2005, Exelon, Generation, ComEd and PECO issued $500 million, $311 million, $459 million and $220 million, net, of commercial paper, respectively.

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In 2006, Exelon terminated its $300 million term loan agreement. See Note 11 of the Combined Notes to the Consolidated Financial Statements for further information.

Retirement of Long-Term Debt to Financing Affiliates. Retirement of long-term debt to financing affiliates during 2006 and 2005 by registrant were as follows:

	Year Ended December 31,
	2006		2005
Exelon	$	910	$	835
ComEd		339		354
PECO		571		481

Contributions from Parent/Member. Contributions from Parent/Member (Exelon) for the years ended December 31, 2006 and 2005 by registrant were as follows:

	Year Ended December 31,
	2006		2005
Generation	$	25	$	843
ComEd		37		834
PECO		181		250

Other. Other significant financing activities for Exelon for the year ended December 31, 2006 and 2005 were as follows:

• Exelon purchased treasury shares totaling $186 million and $362 million during 2006 and 2005, respectively.

• Exelon received proceeds from employee stock plans of $184 million and $222 million during 2006 and 2005, respectively.

• There was $60 million and $0 of excess tax benefits included as a cash inflow in other financing activities during 2006 and 2005, respectively.

Credit Issues

Exelon Credit Facilities

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by the Registrants. At December 31, 2006, Exelon, Generation, ComEd and PECO have access to revolving credit facilities with aggregate bank commitments of $1 billion, $5 billion, $1 billion and $600 million, respectively. These revolving credit agreements are used principally to support the commercial paper programs at the Registrants and to issue letters of credit. During 2006, ComEd borrowed and fully repaid $240 million under its credit agreement.

At December 31, 2006, the Registrants had the following aggregate bank commitments and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

Borrower	Aggregate Bank Commitment (a)		Available Capacity (b)		Outstanding Commercial Paper
Exelon Corporate	$	1,000	$	993	$	150
Generation		5,000		4,920		—
ComEd		1,000		956		60
PECO		600		598		95

(a) Represents the total bank commitments to the borrower under credit agreements to which the borrower is a party.

(b) Available capacity represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

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Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offered 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. In the cases of Exelon, Generation and PECO, the maximum LIBOR adder is 65 basis points; and in the case of ComEd, it is 200 basis points.

The average interest rates on commercial paper in 2006 for Exelon, Generation, ComEd and PECO were approximately 5.02%, 4.99%, 5.06% and 4.97%, respectively.

Each credit agreement requires the affected borrower 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, 2006:

	Exelon	Generation	ComEd	PECO
Credit agreement threshold	2.50 to 1	3.00 to 1	2.25 to 1	2.00 to 1

At December 31, 2006, the Registrants were in compliance with the foregoing thresholds.

The ComEd credit agreement is secured by first mortgage bonds and imposes a restriction on future mortgage bond issuances by ComEd. It requires ComEd to maintain at least $1.75 billion of issuance availability (ignoring any interest coverage test) in the form of “property additions” or “bondable bond retirements” (previously issued, but now retired, bonds), most of which are required to be maintained in the form of “bondable bond retirements.” In general, a dollar of bonds can be issued under ComEd’s Mortgage on the basis of $1.50 of property additions, subject to an interest coverage test, or $1 of bondable bond retirements, which may or may not be subject to an interest coverage test. As of December 31, 2006, ComEd was in compliance with this requirement.

Capital Structure. At December 31, 2006, the capital structures of the Registrants consisted of the following:

	Exelon Consolidated		Generation		ComEd		PECO (a)
Long-term debt	40	%	25	%	33	%	25	%
Long-term debt to affiliates (b)	16		—		9		43
Common equity	43		—		57		29
Member’s equity	—		75		—		—
Preferred securities	—		—		—		1
Commercial paper and notes payable	1		—		1		2

(a) As of December 31, 2006, PECO’s capital structure, excluding the deduction from shareholders’ equity of the $1.1 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 40% common equity, 1% preferred securities, 2% notes payable and 57% long-term debt, including long-term debt to unconsolidated affiliates.

(b) Includes $3.6 billion, $1.0 billion and $2.6 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 the Combined 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

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pool. Participation in the intercompany money pool is subject to authorization by Exelon’s treasurer. Generation, PECO, and BSC may participate in the intercompany 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 intercompany 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 intercompany money pool by participant during 2006 are described in the following table in addition to the net contribution or borrowing as of December 31, 2006:

	Maximum Contributed		Maximum Borrowed		December 31, 2006 Contributed (Borrowed)
Generation	$	83	$	234	$	13
ComEd (a)		—		140		—
PECO		59		183		(45	)
BSC		234		134		(25	)
UII, LLC		5		—		—
Exelon		248		—		56

(a) As of January 10, 2006, ComEd suspended participation in the intercompany money pool. During the first quarter of 2006, ComEd repaid $140 million that it had borrowed from the intercompany money pool.

Security Ratings

The Registrants’ 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, 2006:

	Securities	Moody’s Investors Service	Standard & Poor’s Corporation	Fitch Ratings.
Exelon	Senior unsecured debt	Baa2	BBB	BBB+
	Commercial paper	P2	A2	F2
Generation	Senior unsecured debt	Baa1	BBB+	BBB+
	Commercial paper	P2	A2	F2
ComEd	Senior unsecured debt	Baa3	BB+	BBB
	Senior secured debt	Baa2	BBB	BBB+
	Commercial paper	P3	A3	F2
	Transition bonds (a)	Aaa	AAA	AAA
PECO	Senior unsecured debt	A3	BBB	A-
	Senior secured debt	A2	A-	A
	Commercial paper	P1	A2	F1
	Transition bonds (b)	Aaa	AAA	AAA

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

(b) Issued by PETT, an unconsolidated affiliate of PECO.

On July 26, 2006, Moody’s Investors Service (Moody’s) downgraded the long-term and short-term debt ratings of ComEd. The rating action concluded Moody’s review for possible downgrade that commenced on December 15, 2005. Moody’s attributed the downgrade to a difficult political and regulatory environment in Illinois, uncertainty about the outcome of the electricity supply auction and the expectation of a material regulatory deferral. On October 10, 2006, Moody’s placed ComEd’s security ratings under review for possible downgrade resulting from perceived increasing political and regulatory risk in Illinois.

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On July 31, 2006, Fitch Ratings downgraded the long-term ratings of ComEd. On November 17, 2006, Fitch Ratings placed the ratings of ComEd under Ratings Watch negative due to on-going uncertainty in Illinois resulting from recent legislative actions supporting a rate freeze.

On October 5, 2006, Standard & Poor’s (S&P) downgraded the short-term and long-term security ratings of ComEd due to perceived political risk related to the rate freeze extension proposal. S&P downgraded ComEd’s senior unsecured debt to BB+, which is below investment grade. The ratings on Exelon, PECO and Generation were affirmed. The ratings for all Registrants were placed under Credit Watch with negative implications.

None of the Registrants’ 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 the Registrants’ 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 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 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, 2006, Exelon and PECO had current shelf registration statements for the sale of $300 million and $250 million, respectively, of securities that were effective with the SEC. ComEd, a well-known seasoned issuer as described by the SEC, filed an automatic registration statement on May 10, 2006 and the shelf registration was effective immediately. 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 by ComEd of long-term debt or equity securities 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 anticipated financing needs for a period of time or in connection with a specific financing.

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,

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effective February 8, 2006, the SEC’s financing jurisdiction under PUHCA for ComEd’s and PECO’s short-term financings and Generation’s financings reverted to FERC and Exelon’s financings are no longer subject to regulatory approvals.

In February 2006, ComEd and PECO received orders from FERC approving their requests for short-term financing authority with FERC in the amounts of $2.5 billion and $1.5 billion, respectively, effective February 8, 2006 through December 31, 2007.

Generation currently has blanket financing authority that it received from FERC with its market-based rate authority in November 2000 and that became effective again with the repeal of PUHCA. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information.

Under applicable law, Generation, ComEd and PECO can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd or PECO may limit the dividends that these companies can distribute to Exelon. At December 31, 2006, Exelon had retained earnings of $3.4 billion, including Generation’s undistributed earnings of $1.8 billion, ComEd’s retained deficit of $(193) million consisting of an unappropriated retained deficit of $(1.6) billion partially offset by $1.4 billion of retained earnings appropriated for future dividends, and PECO’s retained earnings of $584 million.

Investments in Synthetic Fuel-Producing Facilities

Exelon, through three separate wholly owned subsidiaries, owns interests in two limited liability companies and one limited partnership that own 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 the tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. On April 11, 2006, the IRS published the 2005 oil Reference Price and it did not exceed the beginning of the phase-out range. Consequently, there was no phase-out of tax credits for calendar year 2005.

The following table (in dollars) provides the estimated phase-out ranges for 2006 and 2007 based on the per barrel price of oil as of December 31, 2006. The table also contains the annual average New York Mercantile Exchange, Inc. index (NYMEX) prices per barrel at December 31, 2006 based on actual prices for the year ended December 31, 2006 and the estimated average futures prices for the year ended December 31, 2007.

	2006		2007
Beginning of Phase-Out Range (a)	$	60	$	62
End of Phase-Out Range (a)		76		77
Annual Average NYMEX		66		64

(a) The estimated 2006 and 2007 phase-out ranges are based upon the actual 2005 phase-out range. The actual 2005 phase-out range was determined using the inflation adjustment factor published by the IRS in April 2006. The actual 2005 phase-out range was increased by 2% per year (Exelon’s estimate of inflation) to arrive at the estimated 2006 and 2007 phase-out ranges.

Exelon and the operators of the synthetic fuel-producing facilities in which Exelon has interests idled the facilities in May 2006. The decision to suspend synthetic fuel production was primarily driven by the level and volatility of oil prices. In addition, the proposed Federal legislation that would have provided certainty that tax credits would exist for 2006 production was not included in the Tax Increase Prevention and Reconciliation Act of 2005. Due to the reduction in oil prices during the third quarter of 2006, the operators resumed production at their synthetic fuel-producing facilities in September 2006

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and produced at full capacity through the remainder of 2006. As of December 31, 2006, Exelon has estimated the 2006 phase-out to be 38%, which has reduced Exelon’s earned after-tax credits of $164 million to $101 million for the year ended December 31, 2006. At December 31, 2006, Exelon has estimated the 2007 phase-out of tax credits to be 18%. Exelon anticipates generating approximately $220 million of cash over the life of these investments, of which $80 million is expected in total for 2007 and 2008, assuming an 18% phase-out of tax credits. Theses estimates may change significantly due to the volatility of oil prices. See Note 12 of the Combined Notes to Consolidated Financial Statements for further discussion. The estimated 2006 and 2007 phase-out ranges are based upon the actual 2005 phase-out range. The actual 2005 phase-out range was determined using the inflation adjustment factor published by the IRS in April 2006. The actual 2005 phase-out range was increased by 2% each year (Exelon’s estimate of inflation) to arrive at the estimated 2006 and 2007 phase-out ranges.

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 2012 and beyond
			2007		2008-2009		2010-2011
Long-term debt	$	9,126	$	246	$	922	$	2,427	$	5,531
Long-term debt to financing trusts		3,596		581		1,664		806		545
Interest payments on long-term debt (a)		4,976		486		888		757		2,845
Interest payments on long-term debt to financing trusts (a)		1,318		225		285		98		710
Capital leases		44		2		4		4		34
Operating leases		716		58		110		93		455
Purchase power obligations (b)		7,802		1,967		1,492		1,134		3,209
Fuel purchase agreements		5,022		1,047		1,463		1,169		1,343
Other purchase obligations (b)(c)		642		292		140		95		115
Chicago agreement (d)		36		6		12		12		6
Spent nuclear fuel obligation		950		—		—		—		950
Pension ERISA minimum funding requirement		32		32		—		—		—
Total contractual obligations	$	34,260	$	4,942	$	6,980	$	6,595	$	15,743

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 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, 2006.

(b) 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, 2006. Expected payments include certain capacity charges which are contingent on plant availability. Does not include ComEd’s supplier forward contracts as these contracts do not require purchases of fixed or minimum quantities. See Notes 4 and 18 of the Combined Notes to the Consolidated Financial Statements.

(c) Commitments for services, materials and information technology.

(d) 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.

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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 2012 and beyond
(in millions)			2007		2008-2009		2010-2011
Long-term debt	$	1,749	$	10	$	19	$	700	$	1,020
Interest payments on long-term debt (a)		786		96		190		138		362
Capital leases		44		2		4		4		34
Operating leases		503		34		61		53		355
Purchase power obligations (b)		7,802		1,967		1,492		1,134		3,209
Fuel purchase agreements		4,516		830		1,317		1,104		1,265
Other purchase commitments (c)		277		165		50		38		24
Pension ERISA minimum funding requirement		24		24		—		—		—
Spent nuclear fuel obligations		950		—		—		—		950
Total contractual obligations	$	16,651	$	3,128	$	3,133	$	3,171	$	7,219

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 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, 2006.

(b) 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, 2006. Expected payments include certain capacity charges which are contingent on plant availability.

(c) Commitments for services, materials and information technology.

ComEd

The following table summarizes ComEd’s future estimated cash payments under existing contractual obligations, including payments due by period.

			Payment due within						Due 2012 and beyond
	Total		2007		2008-2009		2010-2011
Long-term debt	$	3,597	$	147	$	434	$	560	$	2,456
Long-term debt to financing trusts		1,009		308		340		—		361
Interest payments on long-term debt (a)		1,970		192		346		326		1,106
Interest payments on long-term debt to financing trusts (a)		655		57		64		52		482
Operating leases		143		19		38		30		56
Other purchase commitments (b)		38		27		7		4		—
Chicago agreement (c)		36		6		12		12		6
Total contractual obligations	$	7,448	$	756	$	1,241	$	984	$	4,467

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Other purchase commitments include commitments for services, materials and information technology. Other purchase commitments do not include ComEd’s supplier forward contracts as these contracts do not require purchases of fixed or minimum quantities. See Notes 4 and 18 of the Combined Notes to the Consolidated Financial Statements for further detail on ComEd’s supplier forward contracts.

(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.

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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 2012 and beyond
(in millions)			2007		2008-2009		2010-2011
Long-term debt	$	1,471	$	—	$	450	$	267	$	754
Long-term debt to financing trusts		2,588		273		1,325		806		184
Interest payments on long-term debt (a)		851		70		114		105		562
Interest payments on long-term debt to financing trusts (a)		663		168		221		46		228
Operating leases		5		1		2		1		1
Fuel purchase agreements (b)		506		217		146		65		78
Other purchase commitments (c)		209		20		51		47		91
Total contractual obligations	$	6,293	$	749	$	2,309	$	1,337	$	1,898

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2006 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Represents commitments to purchase natural gas and related transportation and storage capacity and services.

(c) Commitments for services, materials and information technology.

For additional information about:

• commercial paper, see Note 11 of the Combined Notes to Consolidated Financial Statements.

• long-term debt, see Note 11 of the Combined Notes to Consolidated Financial Statements.

• capital lease obligations, see Note 11 of the Combined Notes to Consolidated Financial Statements.

• operating leases, energy commitments and fuel purchase agreements, see Note 18 of the Combined Notes to Consolidated Financial Statements.

• the contribution required to Exelon’s pension plans to satisfy ERISA minimum funding requirements, see Note 14 of the Combined Notes to Consolidated Financial Statements.

• the spent nuclear fuel and nuclear decommissioning obligations, see Note 13 of the Combined Notes to Consolidated Financial Statements.

• regulatory commitments, see Note 4 of the Combined 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 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 and Generation as of December 31, 2006 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

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available in specified 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 permitted ComEd through December 31, 2006, 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. At December 31, 2006, the asset retirement obligation recorded within Generation’s Consolidated Balance Sheets related to its nuclear-fueled generating facilities was approximately $3.5 billion. Decommissioning expenditures are expected to occur primarily after the plants are retired. Following the completion of decommissioning activities, any excess nuclear decommissioning trust funds related to the former ComEd and PECO nuclear power plants will be required to be refunded to ComEd or PECO, as appropriate. To fund future decommissioning costs, Generation held approximately $6.4 billion of investments in trust funds, including unrealized gains at December 31, 2006. See Note 13 of the Combined Notes to Consolidated Financial Statements for further discussion of Generation’s decommissioning obligation.

See Note 18 of the Combined Notes to Consolidated Financial Statements for discussion of Exelon’s commercial commitments as of December 31, 2006.

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. While Generation currently has state reviews by governmental agencies pending, they are not expected to have a significant impact on the financial condition or result of operations of Generation.

ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. 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 impacts 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. If a settlement is reached, 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 under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination” (EITF 93-7). Exelon cannot predict the timing of the final resolution of these refund claims.

In 2006, the Joint Committee on Taxation (Joint Committee) completed its review and granted approval for PECO’s income tax refund claims for investment tax credits. A majority of the investment tax credits claimed in the refund related to PECO’s formerly owned generation property. The asset transfer agreement between PECO and Generation provides that PECO retains all current tax and interest benefits associated with the refund claims. Thus, as a result of the agreement, PECO recorded the current tax and interest benefits and Generation recorded the remaining unamortized investment tax credits and the related future deferred tax effects. As a result, the investment tax credit refund and associated interest of $19 million (after tax) have been recorded as a credit in Exelon’s and PECO’s Consolidated Statements of Operations in 2006. Exelon and Generation recorded unamortized investment tax credits and related tax impacts of $10 million (after tax) as a charge to their Consolidated Statements of Operations. The unamortized investment tax credit recorded at Exelon, PECO and Generation will be amortized over the remaining depreciable book lives of the transmission, distribution and generation property using the deferral method pursuant to APB No. 2, “Accounting for the ‘Investment Credit’” and APB No. 4, “Accounting for the ‘Investment Credit’.” In addition, as a result

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of the approval of the refund claim, Exelon and PECO recorded a consulting expense of $3 million (after tax) in 2006. The net after-tax result of this settlement and consulting fees was $6 million, $16 million and $(10) million for Exelon, PECO and Generation, respectively.

During 2006, the IRS indicated to PECO that it agreed with a substantial portion of a research and development refund claim. This refund claim was subject to the approval of the Joint Committee. In 2006, the Joint Committee completed its review and granted approval of the research and development claim. A majority of the refund claim also related to PECO’s formerly owned generation property. Consistent with the investment tax credit refund claims, pursuant to the asset transfer agreement between PECO and Generation, PECO recorded the current tax and interest benefits and Generation recorded the future deferred tax effects. As a result, a research and development credit and the associated interest refund of $20 million (after tax) have been recorded as a credit in Exelon’s and PECO’s Consolidated Statements of Operations in 2006. Exelon and Generation recorded the future deferred tax impact of $11 million as a charge to their Consolidated Statements of Operations. In addition, based on the IRS’ indication of its agreement with a portion of the refund claim, PECO recorded an estimated tax consulting contingent fee of $2 million (after tax) during 2006. The net after-tax result of this settlement and consulting fees was $7 million, $18 million, and $(11) million for Exelon, PECO, and Generation respectively.

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 2 of the Combined 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 $1.0 billion and $2.5 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, 2006.

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 (ANI) Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. See Note 18 of the Combined Notes to Consolidated Financial Statements for further discussion of nuclear insurance. For its types of insured losses,

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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.

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 through November 2010. At December 31, 2006, PECO had sold a $225 million interest in accounts receivable, consisting of a $208 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 $17 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. 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, and a $30 million interest in special-agreement accounts receivable, which was accounted for as a long-term note payable. 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, 2006 and 2005, PECO met this requirement and was not required to make any cash deposits.

Beginning in 2007, this agreement will be subject to the provisions of SFAS No. 156, “Accounting for Servicing of Financial Assets, amendment of FASB Statement No. 140,” which is not expected to have a material impact to PECO.

New Accounting Pronouncements

See Note 1 of the Combined 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 Corporation

The Registrants are 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 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 risk management activities.

Commodity Price Risk (Exelon, Generation and ComEd)

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.

Exelon and Generation

In 2005, Exelon and Generation entered into certain derivatives in the normal course of trading operations to economically hedge a portion of the exposure to a phase-out of the tax credits for the sale of synthetic fuel produced from coal. One of the counterparties has security interests in these derivatives. Including the related mark-to-market gains and losses on these derivatives, interests in synthetic fuel-producing facilities reduced Exelon’s net income by $24 million and increased Exelon’s net income by $81 million and $70 million during the years ended December 31, 2006, 2005 and 2004, respectively. Exelon anticipates that it will continue to record income or losses related to the mark-to-market gains or losses on its derivative instruments and changes to the tax credits earned by Exelon during the period of production due to the volatility of oil prices. Net income or net losses from interests in synthetic fuel-producing facilities are reflected in Exelon's Consolidated Statements of Operations within income taxes, operating and maintenance expense, depreciation and amortization expense, interest expense, equity in losses of unconsolidated affiliates and other, net. See Note 12 of the Combined Notes to consolidated Financial Statements for further information in regards to synthetic fuel activity.

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.

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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 hedged is approximately three years. Generation has estimated a greater than 90% economic and cash flow hedge ratio for 2007 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. A portion of Generation’s hedge may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. 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. The forecasted market price exposure for Generation’s non-trading portfolio associated with a ten percent reduction in the annual average around-the-clock market price of electricity would be a decrease of less than $50 million in net income. This sensitivity assumes that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.

Proprietary Trading Activities. Generation uses financial contracts for proprietary trading purposes. 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, 2006 resulted in a gain of $14 million (before income taxes), which represented a net unrealized mark-to-market gain of $10 million and realized gain of $4 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 $120,000 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, 2006 of $5,165 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 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, 2005 to December 31, 2006. 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, 2005 (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 (a)		(540	)
Total change in fair value during 2006 of contracts recorded in earnings		41
Reclassification to realized at settlement of contracts recorded in earnings		66
Reclassification to realized at settlement from OCI		146
Effective portion of changes in fair value—recorded in OCI		789
Purchase/sale/disposal of existing contracts or portfolios subject to mark-to-market		(3	)
Total mark-to-market energy contract net assets at December 31, 2006	$	499

(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, 2006 and 2005:

	December 31, 2006			December 31, 2005
Current assets	$	1,408		$	916
Noncurrent assets		171			286
Total mark-to-market energy contract assets		1,579			1,202
Current liabilities		(1,003	)		(1,282	)
Noncurrent liabilities		(77	)		(460	)
Total mark-to-market energy contract liabilities		(1,080	)		(1,742	)
Total mark-to-market energy contract net assets (liabilities)	$	499		$	(540	)

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 vary 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, 2006 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 Generation 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 assets (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, the table provides the maturity, by year, of Generation’s net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and either generate or require cash.

	Maturities within															Total Fair Value
(in millions)	2007			2008			2009			2010		2011		2012 and Beyond
Normal Operations, qualifying cash-flow hedge contracts (a):
Actively quoted prices	$	(4	)	$	—		$	—		$	—	$	—	$	—	$	(4	)
Prices provided by other external sources		345			59			14			1		—		—		419
Total	$	341		$	59		$	14		$	1	$	—	$	—	$	415
Normal Operations, other derivative contracts (b):
Actively quoted prices	$	(122	)	$	25		$	(1	)	$	—	$	—	$	—	$	(98	)
Prices provided by other external sources		232			—			1			—		—		—		233
Prices based on model or other valuation methods		(50	)		(1	)		—			—		—		—		(51	)
Total	$	60		$	24		$	—		$	—	$	—	$	—	$	84

(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, 2006. 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, 2006 and December 31, 2005, 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, 2005	$	(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	)
Changes in fair value		476			1			477
Reclassifications from OCI to net income		88			—			88
Accumulated OCI derivative gain (loss) at December 31, 2006	$	250		$	(3	)	$	247

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ComEd

ComEd has derivatives related to one wholesale contract and certain other contracts to manage the market price exposures to several wholesale contracts that extend into 2007, which is beyond the expiration of ComEd’s PPA with Generation. Additionally, the supplier forward contracts that ComEd has entered into as part of the initial ComEd auction (see Note 4 of the Combined Notes to Consolidated Financial Statements) are deemed to be derivatives that qualify for the normal purchases and normal sales exception to SFAS No. 133. ComEd does not enter into derivatives for speculative or trading purposes. As of December 31, 2006, the fair value of the derivative wholesale contract of $5 million was recorded on ComEd’s Consolidated Balance Sheet, which is classified as a current liability. The financial derivative used to manage the market price exposure to several wholesale contracts is designated and effective as a cash flow hedge, as defined in SFAS No. 133. As such, changes in the fair value of the derivative are recorded in OCI and gains and losses are recognized in earnings when the underlying transaction occurs. As of December 31, 2006, the fair value of this contract of $6 million was recorded on ComEd’s Consolidated Balance Sheet as a current liability.

ComEd has exposure to commodity price risk in relation to ancillary services that are purchased from PJM.

Credit Risk (Exelon, Generation, ComEd and PECO)

Generation

Generation’s PPA with ComEd expired at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren auctions. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation will sell more electricity through bilateral agreements with other new and existing counterparties. 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; therefore, Generation’s credit risk profile is anticipated to change based on the credit worthiness of the new and existing counterparties, including ComEd and Ameren. Additionally, due to the possibility of rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to the risk of default and, in the event of a bankruptcy filing by ComEd or Ameren, a risk that the bankruptcy may result in rejection of contracts for the purchase of electricity. A default by ComEd or Ameren on contracts for purchase of electricity, or a rejection of those contracts in a bankruptcy proceeding, could result in a disruption in the wholesale power markets. For additional information on the Illinois auction, the proposed legislation and the various regulatory proceedings, see Note 4 of the Combined Notes to Consolidated Financial Statements.

Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits or letters of credit to be posted by certain counterparties. Generation’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

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The following tables provide information on Generation’s credit exposure, net of collateral, as of December 31, 2006 and 2005. The tables further delineate that exposure by credit rating of the 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 RTOs and Independent System Operators (ISOs) which are discussed below.

Rating as of December 31, 2006 (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	$	1,005	$	268	$	737	1	$	95
Non-investment grade		53		9		44	—		—
No external ratings
Internally rated—investment grade		10		1		9	—		—
Internally rated—non-investment grade		4		3		1	—		—
Total	$	1,072	$	281	$	791	1	$	95

(a) This table does not include accounts receivable exposure.

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.

	Maturity of Credit Risk Exposure
Rating as of December 31, 2006 (a)	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	944	$	61	$	—	$	1,005
Non-investment grade		40		13		—		53
No external ratings
Internally rated—investment grade		10		—		—		10
Internally rated—non-investment grade		3		1		—		4
Total	$	997	$	75	$	—	$	1,072

(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

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grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of 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.

Generation sells output through bilateral contracts. Generation’s sales to counterparties other than ComEd and PECO will increase due to the expiration of the PPA with ComEd at the end of 2006. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. Under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, beginning in 2007, collateral postings will be one-sided from Generation only. That is, if market prices fall below ComEd’s or Ameren’s contracted price levels, neither ComEd nor Ameren is required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation may be required to post collateral. See Note 4 of the Combined Notes to the Consolidated Financial Statements for further information on contracted clearing prices related to the ComEd and Ameren auctions.

As of December 31, 2006, Generation had $26 million of collateral deposit payments being held by counterparties and Generation was holding $273 million of collateral deposits received from counterparties.

RTOs and ISOs. Generation participates in the following established, real-time energy markets that are administered by: PJM, ISO-NE, 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 RTOs or ISOs, as applicable. 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 an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and 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.

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. 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. ComEd is currently unable to predict the impact of the reverse-auction power prices, effective in January 2007, on its provision for uncollectible accounts. ComEd will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. PECO has experienced an increase in its provision for uncollectible accounts in 2006 as compared to 2005 as a result of higher average

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accounts receivable balances in 2006 resulting from increased revenues, changes in PAPUC-approved regulations related to customer payment terms and an increase in the number of low-income customers participating in customer assistance programs, which allow for the forgiveness of certain receivables. PECO’s provision for uncollectible accounts will continue to be affected by changes in prices as well as changes in PAPUC regulations. For the year ended December 31, 2006, ComEd’s ten largest customers represented approximately 3.5% of its electric revenues and PECO's ten largest customers represented approximately 5.9% of its retail electric and gas revenues.

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

Exelon

Exelon’s consolidated balance sheets included a $529 million net investment in direct financing leases as of December 31, 2006. The investment in direct financing leases represents future minimum lease payments due at the end of the thirty-year lives of the leases of $1.5 billion, less unearned income of $963 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, Generation, ComEd and PECO)

Variable Rate Debt. The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants may also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants may 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. At December 31, 2006, the Registrants did not have any material fair-value or cash-flow interest-rate hedges outstanding. As of December 31, 2006, a hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a $4 million, $2 million, $1 million and $1 million decrease in Exelon’s, Generation’s, ComEd’s and PECO’s, respectively, pre-tax earnings.

Fair-Value Hedges. During 2006, ComEd settled its interest-rate swaps designated as fair-value hedges in the aggregate notional amount of $240 million for a cash payment of approximately $1 million.

Cash-Flow Hedges. In 2005, ComEd settled its interest-rate swaps designated as cash-flow hedges in the aggregate notional amount of $325 million due to the underlying transaction for which these interest-rate swaps were entered into was no longer probable of occurring. 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 Operations and within Cash Flows From Investing Activities on the Consolidated Statements of Cash Flows. 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)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of December 31, 2006, Generation’s

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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 $460 million reduction in the fair value of the trust assets.

Exelon and Generation maintain trust assets associated with defined benefit pension and other postretirement benefits. See Defined Benefit Pension and Other Postretirement Benefits in the Critical Accounting Estimates section for information regarding the pension and other postretirement benefit trust assets.

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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, 2006 Compared To Year Ended December 31, 2005

A discussion of Generation’s results of operations for 2006 compared to 2005 is set forth under “Results of Operations—Generation” in “EXELON CORPORATION—Results of Operations” of this Report.

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

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.

Liquidity and Capital Resources

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, participation in the intercompany money pool 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 Issues” 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.

143

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 Issues

A discussion of credit issues pertinent to Generation is set forth under “Credit Issues” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Contractual Obligations 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 and Off-Balance Sheet Obligations” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Critical Accounting Policies and Estimates

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

New Accounting Pronouncements

See Note 1 of the Combined 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 Market Risk—Exelon.”

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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, 2006 Compared to Year Ended December 31, 2005

A discussion of ComEd’s results of operations for 2006 compared 2005 is set forth under “Results of Operations—ComEd” in “EXELON CORPORATION—Results of Operations” of this Report.

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

A discussion of ComEd’s results of operations for 2005 compared to 2004 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, 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 Issues” 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. ComEd did not pay a dividend during 2006.

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.

145

Credit Issues

A discussion of credit issues pertinent to ComEd is set forth under “Credit Issues” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report

Contractual Obligations 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 and Off-Balance Sheet Obligations” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Critical Accounting Policies and Estimates

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

New Accounting Pronouncements

See Note 1 of the Combined 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 Market Risk—Exelon.”

146

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, 2006 Compared To Year Ended December 31, 2005

A discussion of PECO’s results of operations for 2006 compared to 2005 is set forth under “Results of Operations—PECO” in “EXELON CORPORATION—Results of Operations” of this Report.

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.

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 Issues” 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.

147

Credit Issues

A discussion of credit issues pertinent to PECO is set forth under “Credit Issues” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Contractual Obligations and Off-Balance Sheet Obligations

A discussion of PECO’s contractual obligations 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, Generation, ComEd and PECO—Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.

New Accounting Pronouncements

See Note 1 of the Combined 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.”

148

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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, 2006. In making this assessment, management used the criteria in Internal 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, 2006, 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, 2006 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 13, 2007

149

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 consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 conditional asset retirement obligations as of December 31, 2005, its method of accounting for stock-based compensation as of January 1, 2006, and its method of accounting for its defined benefit pension and other postretirement plans as of December 31, 2006.

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, 2006 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, 2006, 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

150

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 13, 2007

151

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)(2)(i) present fairly, in all material respects, the financial position of Exelon Generation Company, LLC and its subsidiaries (Generation) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 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 conditional asset retirement obligations as of December 31, 2005, and its method of accounting for stock-based compensation as of January 1, 2006.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 13, 2007

152

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)(3)(i) present fairly, in all material respects, the financial position of Commonwealth Edison Company and its subsidiaries (ComEd) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 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 conditional asset retirement obligations as of December 31, 2005, and its method of accounting for stock-based compensation as of January 1, 2006.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 13, 2007

153

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)(4)(i) present fairly, in all material respects, the financial position of PECO Energy Company and its subsidiaries (PECO) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 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 conditional asset retirement obligations as of December 31, 2005, and its method of accounting for stock-based compensation as of January 1, 2006.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 13, 2007

154

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Operations

	For the Years Ended December 31,
(in millions, except per share data)	2006			2005			2004
Operating revenues	$	15,655		$	15,357		$	14,133
Operating expenses
Purchased power		2,683			3,162			2,709
Fuel		2,549			2,508			2,220
Operating and maintenance		3,868			3,694			3,700
Impairment of goodwill		776			1,207			—
Depreciation and amortization		1,487			1,334			1,295
Taxes other than income		771			728			710
Total operating expenses		12,134			12,633			10,634
Operating income		3,521			2,724			3,499
Other income and deductions
Interest expense		(616	)		(513	)		(471	)
Interest expense to affiliates, net		(264	)		(316	)		(357	)
Equity in losses of unconsolidated affiliates		(111	)		(134	)		(154	)
Other, net		266			134			60
Total other income and deductions		(725	)		(829	)		(922	)
Income from continuing operations before income taxes and minority interest		2,796			1,895			2,577
Income taxes		1,206			944			713
Income from continuing operations before minority interest		1,590			951			1,864
Minority interest		—			—			6
Income from continuing operations		1,590			951			1,870
Discontinued operations
Loss from discontinued operations (net of taxes of $0, $(3) and $(40), respectively)		(2	)		(4	)		(61	)
Gain on disposal of discontinued operations (net of taxes of $2, $6 and $19, respectively)		4			18			32
Income (loss) from discontinued operations		2			14			(29	)
Income before cumulative effect of changes in accounting principles		1,592			965			1,841
Cumulative effect of changes in accounting principles (net of income taxes of $0, $(27) and $17, respectively)		—			(42	)		23
Net income	$	1,592		$	923		$	1,864
Average shares of common stock outstanding
Basic		670			669			661
Diluted		676			676			669
Earnings per average common share—basic:
Income from continuing operations	$	2.37		$	1.42		$	2.83
Income (loss) from discontinued operations		—			0.02			(0.04	)
Cumulative effect of changes in accounting principles		—			(0.06	)		0.03
Net income	$	2.37		$	1.38		$	2.82
Earnings per average common share—diluted:
Income from continuing operations	$	2.35		$	1.40		$	2.79
Income (loss) from discontinued operations		—			0.02			(0.04	)
Cumulative effect of changes in accounting principles		—			(0.06	)		0.03
Net income	$	2.35		$	1.36		$	2.78
Dividends per common share	$	1.60		$	1.60		$	1.26

See Combined Notes to Consolidated Financial Statements

155

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Cash flows from operating activities
Net income	$	1,592		$	923		$	1,864
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		2,132			1,967			1,933
Cumulative effect of changes in accounting principles (net of income taxes)		—			42			(23	)
Impairment charges		894			1,207			11
Deferred income taxes and amortization of investment tax credits		73			493			202
Net realized and unrealized mark-to-market and hedging transactions		(83	)		(30	)		49
Other non-cash operating activities		197			423			461
Changes in assets and liabilities:
Accounts receivable		(62	)		(279	)		(123	)
Inventories		(59	)		(118	)		(60	)
Accounts payable, accrued expenses and other current liabilities		67			172			133
Counterparty collateral asset		259			(244	)		42
Counterparty collateral liability		172			57			31
Income taxes		69			138			293
Pension and non-pension postretirement benefit contributions		(180	)		(2,225	)		(580	)
Other assets and liabilities		(236	)		(379	)		165
Net cash flows provided by operating activities		4,835			2,147			4,398
Cash flows from investing activities
Capital expenditures		(2,418	)		(2,165	)		(1,921	)
Proceeds from nuclear decommissioning trust fund sales		4,793			5,274			2,320
Investment in nuclear decommissioning trust funds		(5,081	)		(5,501	)		(2,587	)
Acquisitions of businesses, net of cash acquired		—			(97	)		—
Proceeds from sales of investments, long-lived assets and wholly owned subsidiaries, net of $32 of cash sold during 2005		2			107			381
Change in restricted cash		(9	)		21			52
Other investing activities		(49	)		(126	)		16
Net cash flows used in investing activities		(2,762	)		(2,487	)		(1,739	)
Cash flows from financing activities
Issuance of long-term debt		1,370			1,788			232
Retirement of long-term debt		(402	)		(508	)		(1,629	)
Retirement of long-term debt to financing affiliates		(910	)		(835	)		(728	)
Issuance of short-term debt		—			2,500			—
Retirement of short-term debt		(300	)		(2,200	)		—
Change in short-term debt		(685	)		500			164
Dividends paid on common stock		(1,071	)		(1,070	)		(831	)
Proceeds from employee stock plans		184			222			240
Purchase of treasury stock		(186	)		(362	)		(82	)
Other financing activities		11			(54	)		7
Net cash flows used in financing activities		(1,989	)		(19	)		(2,627	)
Increase (decrease) in cash and cash equivalents		84			(359	)		32
Cash and cash equivalents at beginning of period		140			499			467
Cash and cash equivalents at end of period	$	224		$	140		$	499

See Combined Notes to Consolidated Financial Statements

156

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006		2005
Assets
Current assets
Cash and cash equivalents	$	224	$	140
Restricted cash and investments		58		49
Accounts receivable, net
Customer		1,747		1,858
Other		462		337
Mark-to-market derivative assets		1,418		916
Inventories, net, at average cost
Fossil fuel		300		311
Materials and supplies		431		351
Deferred income taxes		—		80
Other		352		595
Total current assets		4,992		4,637
Property, plant and equipment, net		22,775		21,981
Deferred debits and other assets
Regulatory assets		5,808		4,734
Nuclear decommissioning trust funds		6,415		5,585
Investments		643		613
Investments in affiliates		167		200
Goodwill		2,694		3,475
Mark-to-market derivative assets		171		371
Other		654		1,201
Total deferred debits and other assets		16,552		16,179
Total assets	$	44,319	$	42,797

See Combined Notes to Consolidated Financial Statements

157

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006			2005
Liabilities and shareholders’ equity
Current liabilities
Commercial paper and notes payable	$	305		$	1,290
Long-term debt due within one year		248			407
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transition Trust due within one year		581			507
Accounts payable		1,382			1,467
Mark-to-market derivative liabilities		1,015			1,282
Accrued expenses		1,180			1,005
Other		1,084			605
Total current liabilities		5,795			6,563
Long-term debt		8,896			7,759
Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust		2,470			3,456
Long-term debt to other financing trusts		545			545
Deferred credits and other liabilities
Deferred income taxes and unamortized tax credits		5,424			5,078
Asset retirement obligations		3,780			4,157
Pension obligations		747			268
Non-pension postretirement benefits obligations		1,817			1,014
Spent nuclear fuel obligation		950			906
Regulatory liabilities		2,975			2,518
Mark-to-market derivative liabilities		78			522
Other		782			798
Total deferred credits and other liabilities		16,553			15,261
Total liabilities		34,259			33,584
Commitments and contingencies
Minority interest of consolidated subsidiaries		—			1
Preferred securities of subsidiaries		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 670 and 666 shares outstanding at December 31, 2006 and 2005, respectively)		8,314			7,987
Treasury stock, at cost (13 and 9 shares held at December 31, 2006 and 2005, respectively)		(630	)		(444	)
Retained earnings		3,426			3,206
Accumulated other comprehensive loss, net		(1,137	)		(1,624	)
Total shareholders’ equity		9,973			9,125
Total liabilities and shareholders’ equity	$	44,319		$	42,797

See Combined Notes to Consolidated Financial Statements

158

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity

(Dollars in millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
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
Net income	—		—		—			1,592			—			1,592
Long-term incentive plan activity	6,385		313		—			—			—			313
Employee stock purchase plan issuances	280		14		—			—			—			14
Common stock purchases	—		—		(186	)		—			—			(186	)
Common stock dividends declared	—		—		—			(1,372	)		—			(1,372	)
Adjustment to initially apply SFAS No. 158, net of income taxes of $773	—		—		—			—			(1,302	)		(1,302	)
Other comprehensive income, net of income taxes of $1,179	—		—		—			—			1,789			1,789
Balance, December 31, 2006	682,474	$	8,314	$	(630	)	$	3,426		$	(1,137	)	$	9,973

See Combined Notes to Consolidated Financial Statements

159

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Comprehensive Income

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Net income	$	1,592		$	923		$	1,864
Other comprehensive income (loss)
Minimum pension liability, net of income taxes of $674, $3, and $(228), respectively		1,138			10			(392	)
Net unrealized gain (loss) on cash-flow hedges, net of income taxes of $368, $(133), and $6, respectively		561			(199	)		8
Foreign currency translation adjustment, net of income taxes of $0, $(1), and $1, respectively		—			(3	)		1
Unrealized gain on marketable securities, net of income taxes of $137, $4, and $31, respectively		92			14			52
State income tax rate alignment		(2	)		—			—
Other comprehensive income (loss)		1,789			(178	)		(331	)
Comprehensive income	$	3,381		$	745		$	1,533

See Combined Notes to Consolidated Financial Statements

160

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Operations

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Operating revenues
Operating revenues	$	4,401		$	4,198		$	3,862
Operating revenues from affiliates		4,742			4,848			3,841
Total operating revenues		9,143			9,046			7,703
Operating expenses
Purchased power		2,027			2,569			2,307
Fuel		1,951			1,913			1,704
Operating and maintenance		2,041			2,051			1,962
Operating and maintenance from affiliates		264			237			239
Depreciation and amortization		279			254			286
Taxes other than income		185			170			166
Total operating expense		6,747			7,194			6,664
Operating income		2,396			1,852			1,039
Other income and deductions
Interest expense		(155	)		(125	)		(100	)
Interest expense to affiliates, net		(4	)		(3	)		(3	)
Equity in losses of unconsolidated affiliates		(9	)		(1	)		(14	)
Other, net		41			95			130
Total other income and deductions		(127	)		(34	)		13
Income from continuing operations before income taxes and minority interest		2,269			1,818			1,052
Income taxes		866			709			401
Income from continuing operations before minority interest		1,403			1,109			651
Minority interest		—			—			6
Income from continuing operations		1,403			1,109			657
Discontinued operations
Loss from discontinued operations (net of taxes of $0, $(1) and $(29), respectively)		—			—			(16	)
Gain on disposal of discontinued operations (net of taxes of $2, $6 and $0, respectively)		4			19			—
Income (loss) from discontinued operations		4			19			(16	)
Income before cumulative effect of changes in accounting principles		1,407			1,128			641
Cumulative effect of changes in accounting principles (net of income taxes of $0, $(19) and $22, respectively)		—			(30	)		32
Net income	$	1,407		$	1,098		$	673

See Combined Notes to Consolidated Financial Statements

161

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Cash flows from operating activities
Net income	$	1,407		$	1,098		$	673
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		924			886			923
Cumulative effect of changes in accounting principles (net of income taxes)		—			30			(32	)
Deferred income taxes and amortization of investment tax credits		174			330			124
Net realized and unrealized mark-to-market and hedging transactions		(107	)		(6	)		37
Other non-cash operating activities		53			22			103
Changes in assets and liabilities:
Accounts receivable		(9	)		(64	)		(67	)
Receivables from and payables to affiliates, net		(35	)		(101	)		11
Inventories		(1	)		(82	)		(35	)
Accounts payable, accrued expenses and other current liabilities		(27	)		143			45
Counterparty collateral asset		259			(244	)		42
Counterparty collateral liability		172			57			31
Income taxes		97			178			228
Pension and non-pension postretirement benefit contributions		(78	)		(962	)		(220	)
Other assets and liabilities		(279	)		(313	)		84
Net cash flows provided by operating activities		2,550			972			1,947
Cash flows from investing activities
Capital expenditures		(1,109	)		(1,067	)		(960	)
Proceeds from nuclear decommissioning trust fund sales		4,793			5,274			2,320
Investment in nuclear decommissioning trust funds		(5,081	)		(5,501	)		(2,587	)
Acquisition of businesses, net of cash acquired		—			(97	)		—
Proceeds from sales of investments		—			103			24
Changes in Exelon intercompany money pool contributions		(13	)		—			—
Change in restricted cash		1			(1	)		36
Other investing activities		3			(5	)		64
Net cash flows used in investing activities		(1,406	)		(1,294	)		(1,103	)
Cash flows from financing activities
Issuance of long-term debt		—			—			157
Retirement of long-term debt		(12	)		(14	)		(62	)
Change in short-term debt		(311	)		311			—
Changes in Exelon intercompany money pool borrowings		(92	)		(191	)		(162	)
Distribution to member		(609	)		(857	)		(662	)
Contribution from member		25			843			17
Other financing activities		(51	)		1			(27	)
Net cash flows (used in) provided by financing activities		(1,050	)		93			(739	)
Increase (decrease) in cash and cash equivalents		94			(229	)		105
Cash and cash equivalents at beginning of period		34			263			158
Cash and cash equivalents at end of period	$	128		$	34		$	263

See Combined Notes to Consolidated Financial Statements

162

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006		2005
Assets
Current assets
Cash and cash equivalents	$	128	$	34
Restricted cash and investments		2		3
Accounts receivable, net
Customer		575		585
Other		122		109
Mark-to-market derivative assets		1,408		916
Receivables from affiliates		437		411
Inventories, net, at average cost
Fossil fuel		127		160
Materials and supplies		335		290
Deferred income taxes		—		35
Contributions to Exelon intercompany money pool		13		—
Prepayments and other current assets		286		497
Total current assets		3,433		3,040
Property, plant and equipment, net		7,514		7,464
Deferred debits and other assets
Nuclear decommissioning trust funds		6,415		5,585
Investments		18		15
Investments in affiliates		97		105
Prepaid pension asset		996		1,013
Mark-to-market derivative assets		171		286
Other		265		216
Total deferred debits and other assets		7,962		7,220
Total assets	$	18,909	$	17,724

See Combined Notes to Consolidated Financial Statements

163

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006		2005
Liabilities and member’s equity
Current liabilities
Commercial paper	$	—	$	311
Long-term debt due within one year		12		12
Accounts payable		899		954
Mark-to-market derivative liabilities		1,003		1,282
Payables to affiliates		—		4
Borrowings from Exelon intercompany money pool		—		92
Accrued expenses		496		415
Deferred income taxes		142		—
Other		362		330
Total current liabilities		2,914		3,400
Long-term debt		1,778		1,788
Deferred credits and other liabilities
Asset retirement obligations		3,602		3,986
Pension obligation		37		13
Non-pension postretirement benefits obligations		538		541
Spent nuclear fuel obligation		950		906
Deferred income taxes and unamortized investment tax credits		1,383		865
Payables to affiliates		1,911		1,503
Mark-to-market derivative liabilities		77		460
Other		238		280
Total deferred credits and other liabilities		8,736		8,554
Total liabilities		13,428		13,742
Commitments and contingencies
Minority interest of consolidated subsidiary		1		2
Member’s equity
Membership interest		3,267		3,220
Undistributed earnings		1,800		1,002
Accumulated other comprehensive income (loss), net		413		(242	)
Total member’s equity		5,480		3,980
Total liabilities and member’s equity	$	18,909	$	17,724

See Combined Notes to Consolidated Financial Statements

164

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, 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
Net income		—			1,407			—			1,407
Distribution to member		—			(609	)		—			(609	)
Allocation of tax benefit from member		47			—			—			47
Adjustment to initially apply SFAS No. 158, net of income taxes of $0		—			—			(1	)		(1	)
Other comprehensive income, net of income taxes of $507		—			—			656			656
Balance, December 31, 2006	$	3,267		$	1,800		$	413		$	5,480

See Combined Notes to Consolidated Financial Statements

165

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Comprehensive Income

	For the Years Ended December 31,
(in millions)	2006		2005			2004
Net income	$	1,407	$	1,098		$	673
Other comprehensive income (loss)
Net unrealized gain (loss) on cash-flow hedges, net of income taxes of $371, $(116) and $8, respectively		565		(172	)		7
Foreign currency translation adjustment, net of income taxes of $0, $0 and $0, respectively		—		(1	)		1
Unrealized gain on marketable securities, net of income taxes of $136, $4 and $31, respectively		91		14			49
Other comprehensive income (loss)		656		(159	)		57
Comprehensive income	$	2,063	$	939		$	730

See Combined Notes to Consolidated Financial Statements

166

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Operations

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Operating revenues
Operating revenues	$	6,091		$	6,253		$	5,782
Operating revenues from affiliates		10			11			21
Total operating revenues		6,101			6,264			5,803
Operating expenses
Purchased power		363			346			214
Purchased power from affiliate		2,929			3,174			2,374
Operating and maintenance		525			640			705
Operating and maintenance from affiliates		220			193			192
Impairment of goodwill		776			1,207			—
Depreciation and amortization		430			413			410
Taxes other than income		303			303			291
Total operating expenses		5,546			6,276			4,186
Operating income (loss)		555			(12	)		1,617
Other income and deductions
Interest expense		(236	)		(203	)		(258	)
Interest expense to affiliates, net		(72	)		(88	)		(91	)
Equity in losses of unconsolidated affiliates		(10	)		(14	)		(19	)
Other, net		96			4			(116	)
Total other income and deductions		(222	)		(301	)		(484	)
Income (loss) before income taxes and cumulative effect of a change in accounting principle		333			(313	)		1,133
Income taxes		445			363			457
Income (loss) before cumulative effect of a change in accounting principle		(112	)		(676	)		676
Cumulative effect of a change in accounting principle (net of income taxes of $0, $(6) and $0, respectively)		—			(9	)		—
Net income (loss)	$	(112	)	$	(685	)	$	676

See Combined Notes to Consolidated Financial Statements

167

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Cash flows from operating activities
Net income (loss)	$	(112	)	$	(685	)	$	676
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation, amortization and accretion		431			413			410
Cumulative effect of a change in accounting principle (net of income taxes)		—			9			—
Deferred income taxes and amortization of investment tax credits		103			226			153
Impairment of goodwill		776			1,207			—
Net realized and unrealized mark-to-market and hedging transactions		5			—			—
Other non-cash operating activities		(134	)		140			248
Changes in assets and liabilities:
Accounts receivable		6			(108	)		(82	)
Inventories		(34	)		(1	)		(4	)
Accounts payable, accrued expenses and other current liabilities		38			45			61
Receivables from and payables to affiliates, net		(58	)		28			30
Income taxes		14			(137	)		109
Pension and non-pension postretirement benefit contributions		(47	)		(865	)		(244	)
Other assets and liabilities		(1	)		(25	)		(27	)
Net cash flows provided by operating activities		987			247			1,330
Cash flows from investing activities
Capital expenditures		(911	)		(776	)		(721	)
Changes in Exelon intercompany money pool contributions		—			308			97
Receipt of notes receivable from affiliates		—			—			1,071
Change in restricted cash		—			—			20
Other investing activities		17			(11	)		19
Net cash flows provided by (used in) investing activities		(894	)		(479	)		486
Cash flows from financing activities
Issuance of long-term debt		1,074			91			—
Retirement of long-term debt		(327	)		(417	)		(1,231	)
Retirement of long-term debt to ComEd Transitional Funding Trust		(339	)		(354	)		(335	)
Change in Exelon intercompany money pool borrowings		(140	)		140			—
Retirement of preferred stock		—			(9	)		—
Change in short-term debt		(399	)		459			—
Dividends paid on common stock		—			(498	)		(457	)
Contributions from parent		37			834			175
Other financing activities		(2	)		(6	)		28
Net cash flow provided by (used in) financing activities		(96	)		240			(1,820	)
Increase (decrease) in cash and cash equivalents		(3	)		8			(4	)
Cash and cash equivalents at beginning of period		38			30			34
Cash and cash equivalents at end of period	$	35		$	38		$	30

See Combined Notes to Consolidated Financial Statements

168

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006		2005
Assets
Current assets
Cash and cash equivalents	$	35	$	38
Accounts receivable, net
Customer		740		806
Other		62		46
Inventories, net, at average cost		83		50
Deferred income taxes		29		13
Receivables from affiliates		18		37
Other		40		34
Total current assets		1,007		1,024
Property, plant and equipment, net		10,457		9,906
Deferred debits and other assets
Regulatory assets		532		280
Investments		44		41
Investments in affiliates		20		34
Goodwill		2,694		3,475
Receivables from affiliates		1,774		1,447
Prepaid pension asset		914		938
Other		332		346
Total deferred debits and other assets		6,310		6,561
Total assets	$	17,774	$	17,491

See Combined Notes to Consolidated Financial Statements

169

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006			2005
Liabilities and shareholders’ equity
Current liabilities
Commercial paper	$	60		$	459
Long-term debt due within one year		147			328
Long-term debt to ComEd Transitional Funding Trust due within one year		308			307
Accounts payable		203			223
Accrued expenses		467			417
Payables to affiliates		219			278
Borrowings from Exelon intercompany money pool		—			140
Customer deposits		114			110
Other		82			46
Total current liabilities		1,600			2,308
Long-term debt		3,432			2,500
Long-term debt to ComEd Transitional Funding Trust		340			680
Long-term debt to other financing trusts		361			361
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,310			2,190
Asset retirement obligations		156			151
Non-pension postretirement benefits obligations		176			175
Regulatory liabilities		2,824			2,450
Other		277			280
Total deferred credits and other liabilities		5,743			5,246
Total liabilities		11,476			11,095
Commitments and contingencies
Shareholders’ equity
Common stock		1,588			1,588
Other paid in capital		4,906			4,890
Retained deficit		(193	)		(81	)
Accumulated other comprehensive loss, net		(3	)		(1	)
Total shareholders’ equity		6,298			6,396
Total liabilities and shareholders’ equity	$	17,774		$	17,491

See Combined Notes to Consolidated Financial Statements

170

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 (Deficits) Unappropriated			Retained Earnings Appropriated			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
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	)
Resolution of certain tax matters		—		—			(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	)
Redemption of preferred stock		—		(7	)		—			—			—			—			—			(7	)
Resolution of certain tax matters		—		—			(14	)		—			—			—			—			(14	)
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
Net loss		—		—			—			—			(112	)		—			—			(112	)
Allocation of tax benefit from parent		—		—			21			—			—			—			—			21
Appropriation of retained earnings for future dividends		—		—			—			—			(340	)		340			—			—
Resolution of certain tax matters		—		—			(5	)		—			—			—			—			(5	)
Other comprehensive loss, net of income taxes of $(1)		—		—			—			—			—			—			(2	)		(2	)
Balance, December 31, 2006	$	1,588	$	—		$	4,906		$	—		$	(1,632	)	$	1,439		$	(3	)	$	6,298

See Combined Notes to Consolidated Financial Statements

171

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income (Loss)

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Net income (loss)	$	(112	)	$	(685	)	$	676
Other comprehensive income (loss)
Foreign currency translation adjustment, net of income taxes of $0, $(1) and $1, respectively		—			(2	)		—
Unrealized gain on marketable securities, net of income taxes of $1, $0 and $1, respectively		2			1			1
Unrealized loss on cash-flow hedges, net of income taxes of $(2), $0 and $0, respectively		(4	)		—			—
Other comprehensive income (loss)		(2	)		(1	)		1
Comprehensive income (loss)	$	(114	)	$	(686	)	$	677

See Combined Notes to Consolidated Financial Statements

172

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Operations

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Operating revenues
Operating revenues	$	5,153		$	4,893		$	4,468
Operating revenues from affiliates		15			17			19
Total operating revenues		5,168			4,910			4,487
Operating expenses
Purchased power		293			248			197
Purchased power from affiliate		1,811			1,670			1,447
Fuel		598			596			511
Fuel from affiliate		—			1			17
Operating and maintenance		498			440			440
Operating and maintenance from affiliates		130			109			107
Depreciation and amortization		710			566			518
Taxes other than income		262			231			236
Total operating expenses		4,302			3,861			3,473
Operating income		866			1,049			1,014
Other income and deductions
Interest expense		(73	)		(56	)		(56	)
Interest expense to affiliates, net		(193	)		(223	)		(247	)
Equity in losses of unconsolidated affiliates		(9	)		(16	)		(25	)
Other, net		30			13			18
Total other income and deductions		(245	)		(282	)		(310	)
Income before income taxes and cumulative effect of a change in accounting principle		621			767			704
Income taxes		180			247			249
Income before cumulative effect of a change in accounting principle		441			520			455
Cumulative effect of a change in accounting principle (net of income taxes of $0, ($2) and $0, respectively)		—			(3	)		—
Net income		441			517			455
Preferred stock dividends		4			4			3
Net income on common stock	$	437		$	513		$	452

See Combined Notes to Consolidated Financial Statements

173

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Cash flows from operating activities
Net income	$	441		$	517		$	455
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		710			566			518
Cumulative effect of a change in accounting principle (net of income taxes)		—			3			—
Deferred income taxes and amortization of investment tax credits		(220	)		(82	)		(98	)
Other non-cash operating activities		109			95			118
Changes in assets and liabilities:
Accounts receivable		(69	)		(118	)		(59	)
Inventories		(24	)		(35	)		(21	)
Accounts payable, accrued expenses and other current liabilities		14			13			18
Receivables from and payables to affiliates, net		26			31			(4	)
Income taxes		13			(99	)		57
Pension and non-pension postretirement benefit contributions		(32	)		(189	)		(14	)
Other assets and liabilities		49			2			13
Net cash flows provided by operating activities		1,017			704			983
Cash flows from investing activities
Capital expenditures		(345	)		(298	)		(225	)
Changes in Exelon intercompany money pool contributions		8			26			(34	)
Change in restricted cash		(2	)		27			(3	)
Other investing activities		7			4			11
Net cash flows used in investing activities		(332	)		(241	)		(251	)
Cash flows from financing activities
Issuance of long-term debt		296			—			75
Retirement of long-term debt		(13	)		(16	)		(235	)
Retirement of long-term debt to PECO Energy Transition Trust		(571	)		(481	)		(393	)
Change in short-term debt		(125	)		220			(46	)
Changes in Exelon intercompany money pool borrowings		45			—			—
Dividends paid on common and preferred stock		(506	)		(473	)		(394	)
Contribution from parent		181			250			312
Other financing activities		—			—			5
Net cash flows used in financing activities		(693	)		(500	)		(676	)
Increase (decrease) in cash and cash equivalents		(8	)		(37	)		56
Cash and cash equivalents at beginning of period		37			74			18
Cash and cash equivalents at end of period	$	29		$	37		$	74

See Combined Notes to Consolidated Financial Statements

174

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006		2005
Assets
Current assets
Cash and cash equivalents	$	29	$	37
Restricted cash		4		2
Accounts receivable, net
Customer		426		454
Other		79		57
Affiliate		—		13
Inventories, net, at average cost
Gas		173		151
Materials and supplies		13		11
Contributions to Exelon intercompany money pool		—		8
Deferred income taxes		25		7
Deferred energy costs		—		39
Other		13		16
Total current assets		762		795
Property, plant and equipment, net		4,651		4,471
Deferred debits and other assets
Regulatory assets		3,896		4,454
Investments		21		22
Investment in affiliates		64		73
Receivable from affiliate		151		68
Other		228		203
Total deferred debits and other assets		4,360		4,820
Total assets	$	9,773	$	10,086

See Combined Notes to Consolidated Financial Statements

175

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2006			2005
Liabilities and shareholders’ equity
Current liabilities
Commercial paper	$	95		$	220
Borrowings from Exelon intercompany money pool		45			—
Long-term debt to PECO Energy Transition Trust due within one year		273			199
Accounts payable		175			182
Accrued expenses		121			92
Payables to affiliates		203			178
Customer deposits		50			54
Over-recovered energy costs		6			—
Other		10			11
Total current liabilities		978			936
Long-term debt		1,469			1,183
Long-term debt to PECO Energy Transition Trust		2,131			2,776
Long-term debt to other financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,601			2,798
Asset retirement obligations		21			20
Non-pension postretirement benefit obligations		283			278
Regulatory liabilities		151			68
Other		146			139
Total deferred credits and other liabilities		3,202			3,303
Total liabilities		7,964			8,382
Commitments and contingencies
Shareholders’ equity
Common stock		2,223			2,193
Preferred stock		87			87
Receivable from parent		(1,090	)		(1,232	)
Retained earnings		584			649
Accumulated other comprehensive income, net		5			7
Total shareholders’ equity		1,809			1,704
Total liabilities and shareholders’ equity	$	9,773		$	10,086

See Combined Notes to Consolidated Financial Statements

176

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, 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
Net income		—		—		—			441			—			441
Common stock dividends		—		—		—			(502	)		—			(502	)
Preferred stock dividends		—		—		—			(4	)		—			(4	)
Repayment of receivable from parent		—		—		142			—			—			142
Allocation of tax benefit from parent		30		—		—			—			—			30
Other comprehensive loss, net of income taxes of $(2)		—		—		—			—			(2	)		(2	)
Balance, December 31, 2006	$	2,223	$	87	$	(1,090	)	$	584		$	5		$	1,809

See Combined Notes to Consolidated Financial Statements

177

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income

	For the Years Ended December 31,
(in millions)	2006			2005			2004
Net income	$	441		$	517		$	455
Other comprehensive income (loss)
Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $(2), $(3) and $(1), respectively		(2	)		(3	)		1
Unrealized gain on marketable securities, net of income taxes of $0, $0 and $(1), respectively		—			—			2
Other comprehensive income (loss)		(2	)		(3	)		3
Comprehensive income	$	439		$	514		$	458

See Combined Notes to Consolidated Financial Statements

178

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements

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

1. Significant Accounting Policies

Description of Business (Exelon, Generation, ComEd and PECO)

Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the generation, energy delivery and other businesses discussed below. The generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail sales operations of Exelon Generation Company, LLC (Generation). The energy delivery businesses include the purchase and regulated retail and wholesale sale of electricity and the provision of 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 the provision of distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. 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 2—Acquisitions and Dispositions for information regarding the disposition of businesses within the Enterprises segment and Note 20—Segment Information for information regarding Exelon’s operating segments.

Basis of Presentation (Exelon, Generation, ComEd and PECO)

Exelon’s consolidated financial statements include the accounts of entities in which Exelon has a controlling financial interest, other than certain financing trusts of ComEd and PECO described below, and Generation’s and PECO’s proportionate interests in jointly owned electric utility property, 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%; PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred stock; and Southeast Chicago Energy Project, LLC (SCEP), of which Exelon and Generation owned 72% through the second quarter of 2006 when they purchased the remaining interest in SCEP. Exelon has reflected the third-party interests in the above majority-owned investments as minority interests in its consolidated financial statements.

Generation’s consolidated financial statements include the accounts of its subsidiaries, including AmerGen Energy Company, LLC, and Exelon Energy Company, LLC. All intercompany transactions have been eliminated.

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 and are pending legal dissolution, which is expected in 2007. All intercompany transactions have been eliminated.

179

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

In accordance with Financial Accounting Standards Board (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 and Generation’s financial statements as of March 31, 2004. As further discussed in Note 2 - Acquisitions and Dispositions, Generation sold its investment in Sithe on January 31, 2005. Additionally, 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 Combined 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 16 - Common Stock for additional information regarding the stock split.

Reclassifications (Exelon, Generation, ComEd and PECO)

Certain prior year amounts have been reclassified in the financial statements for comparative purposes. The reclassifications did not affect net income.

Use of Estimates (Exelon, Generation, ComEd and PECO)

The preparation of financial statements of each of Exelon, Generation, ComEd and PECO (collectively, the Registrants) 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 other 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, ComEd and PECO)

Exelon, ComEd and PECO account for their 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

180

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 Statement of Financial Accounting Standards (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 their 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, ComEd and PECO continue to evaluate their 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 was no longer able to meet the provisions of SFAS No. 71, Exelon, ComEd and PECO would be required to eliminate from their financial statements the effects of regulation for that portion, which could have a material impact on their financial condition and results of operations. See Note 4—Regulatory Issues for further information regarding the repeal of PUHCA effective February 8, 2006 and the regulatory and political environment in Illinois.

Segment Information (Generation, ComEd and PECO)

Generation, ComEd and PECO each constitute one operating segment. See Note 20 – Segment Information for information regarding Exelon’s operating segments.

Variable Interest Entities (Exelon, Generation, ComEd and PECO)

FIN 46 and its revision FIN 46-R addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for the Registrants’ variable interest entities created after January 31, 2003. FIN 46-R was effective December 31, 2003 for the Registrants’ variable interest entities that were considered to be special-purpose entities and as of March 31, 2004 for all other variable interest entities.

Exelon and 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 Exelon had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owned and operated power-generating facilities and was sold by Generation on January 31, 2005. See Note 2—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 formed prior to December 31, 2003 of ComEd, namely ComEd Financing II, ComEd Financing III, ComEd Funding LLC and ComEd Transitional Funding Trust, and the other financing trusts of PECO, namely PECO Trust III and PECO Energy Transition Trust (PETT), were deconsolidated from Exelon’s, ComEd’s and

181

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO’s financial statements. The following table shows the amounts recorded as debt to financing trusts within the Consolidated Balance Sheets:

As of the Year Ended December 31,	Exelon		ComEd		PECO
2006	$	3.6 billion	$	1.0 billion	$	2.6 billion
2005		4.5 billion		1.3 billion		3.2 billion

This change in presentation related to the financing trusts had no effect on Exelon’s, ComEd’s or PECO’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 $34 million and $64 million respectively, at December 31, 2006 and $46 million and $73 million, respectively, at December 31, 2005.

Revenues (Exelon, Generation, ComEd and PECO)

Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, the Registrants accrue 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 expense over the lives of the contracts. Certain option contracts and swap arrangements which meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenues and expenses, unless hedge accounting is applied. If the derivatives meet hedging criteria, changes in fair value are recorded in OCI. 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 and Generation account for their 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 and Generation account 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 states 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.

182

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon and Generation present, net within revenues, purchased power and fuel expenses totaling $561 million, $1,099 million and $980 million during 2006, 2005 and 2004, respectively.

Income Taxes (Exelon, Generation, ComEd and PECO)

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 Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property.

Pursuant to the Internal Revenue Code and relevant state taxing authorities, Exelon and its subsidiaries file consolidated income tax returns for Federal and certain state jurisdictions, which include its subsidiaries in which it owns at least 80% of the outstanding stock. The Registrants record 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, ComEd and PECO are parties 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 and Retired Debt (Exelon, Generation, ComEd and PECO)

Consistent with rate recovery for rate-making purposes, ComEd’s and PECO’s 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, or over the life of the original debt issuance if the debt is not refinanced. Losses on other reacquired debt are recognized as incurred in the Registrants’ Consolidated Statements of Operations.

Comprehensive Income (Exelon, Generation, ComEd and PECO)

Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. See the Consolidated Statements of Changes in Shareholders’ / Member’s Equity and the Consolidated Statements of Comprehensive Income for further detail, including the components of comprehensive income.

Cash and Cash Equivalents (Exelon, Generation, ComEd and PECO)

The Registrants consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Investments (Exelon, Generation and PECO)

As of December 31, 2006 and 2005, Exelon’s restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. As of December 31, 2006 and 2005, Generation’s restricted cash and investments primarily represented

183

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

restricted funds for payment of certain environmental liabilities. As of December 31, 2006 and 2005, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s Mortgage Indenture. PECO’s restricted cash is not available for general operations until released from the Mortgage Indenture.

Restricted cash and investments not available for general operations or to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2006 and 2005, Exelon and Generation had restricted cash and investments in the nuclear decommissioning trust funds classified as noncurrent assets.

Allowance for Uncollectible Accounts (Exelon, Generation, ComEd and PECO)

The allowance for uncollectible accounts reflects the Registrants’ best estimates of probable losses in the accounts receivable balances. The allowance is based on known troubled accounts, historical experience and other currently available evidence. For ComEd and PECO, customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Customer accounts are written off based upon approved regulatory requirements.

The following table summarizes the provision for uncollectible accounts for the years ended December 31, 2006, 2005 and 2004:

For the Year Ended December 31,	Exelon		Generation		ComEd		PECO
2006	$	94	$	2	$	33	$	58
2005		77		—		24		45
2004		87		2		37		47

Inventories (Exelon, Generation, ComEd and PECO)

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 (Exelon and Generation)

Emission allowances are included in inventory 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 and Generation’s emission allowance balances as of December 31, 2006 and 2005 were $94 million and $112 million, respectively.

184

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Marketable Securities (Exelon, Generation, ComEd and PECO)

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 gains and losses, net of tax, on nuclear decommissioning trust funds transferred to Generation from ComEd and PECO are considered in the determination of the regulatory liabilities at Exelon and in the noncurrent payables to affiliates at Generation. Unrealized gains on nuclear decommissioning trust funds are included in Exelon’s regulatory liabilities or other comprehensive income at Exelon and in noncurrent payables to affiliates or other comprehensive income at Generation. See Note 19—Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities. Unrealized gains, net of tax, for ComEd’s and PECO’s available-for-sale securities are reported in other comprehensive income.

Beginning in 2006 and in connection with the issuance of FASB Staff Position FAS 115-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (FSP 115-1), Generation considers all nuclear decommissioning trust fund investments in an unrealized loss position to be other-than-temporarily impaired. As a result of certain Nuclear Regulatory Commission (NRC) restrictions, Generation is unable to demonstrate its ability and intent to hold the nuclear decommissioning trust fund investments through a recovery period and accordingly recognizes any unrealized holding losses immediately. At December 31, 2006 and 2005, the Registrants had no held-to-maturity securities. See Note 9—Fair Value of Financial Assets and Liabilities for information regarding marketable securities held by nuclear decommissioning trust funds.

Purchased Gas Adjustment Clause (Exelon and PECO)

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, 2006, over-recovered energy costs of $6 million were recorded as current liabilities on Exelon’s and PECO’s Consolidated Balance Sheets. At December 31, 2005, deferred energy costs of $39 million were recorded as current assets on Exelon’s and PECO’s Consolidated Balance Sheets.

Leases (Exelon, Generation, ComEd and PECO)

The Registrants account for leases in accordance with SFAS No. 13, “Accounting for Leases” and determine whether their 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, the Registrants determine whether the lease is an operating or capital lease based upon its terms and characteristics. Several of Generation’s long-term power purchase agreements (PPAs) 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.

185

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Property, Plant and Equipment (Exelon, Generation, ComEd and PECO)

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 Generation, upon retirement, the cost of property is charged to accumulated depreciation. 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. 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 regulatory 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.

See Note 6—Property, Plant and Equipment, Note 7—Jointly Owned Electric Utility Plant and Note 19—Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel (Exelon and Generation)

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 through fuel expense at one mill ($.001) per kilowatthour (kWh) 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 (Exelon and Generation)

Costs associated with nuclear outages are recorded in the period incurred.

New Site Development Costs (Exelon and Generation)

New site development costs represent certain costs incurred in the planning and evaluation stage of new stations and are capitalized when the project is considered probable of occurrence, which is based on various factors.

186

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Capitalized Software Costs (Exelon, Generation, ComEd and PECO)

Costs incurred during the application development stage of software projects that are developed or obtained for internal use are capitalized. 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. The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year:

Net unamortized software costs	Exelon		Generation		ComEd		PECO
December 31, 2006	$	295	$	46	$	118	$	63
December 31, 2005		264		31		122		30

Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO
2006	$	77	$	13	$	21	$	22
2005		76		11		22		23
2004		80		16		34		12

Depreciation and Amortization (Exelon, Generation, ComEd and PECO)

Depreciation is generally provided over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. ComEd’s depreciation includes a provision for estimated removal costs as authorized by the ICC. 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 PECO’s depreciation rates.

Average Service Life in Years by Asset Category	Exelon	Generation	ComEd	PECO
2006
Electric—transmission and distribution	5-75	N/A	5-75	5-65
Electric—generation	5-61	5-61	N/A	N/A
Gas	5-66	N/A	N/A	5-66
Common—electric and gas	5-50	N/A	N/A	5-50

Average Service Life in Years by Asset Category	Exelon	Generation	ComEd	PECO
2005
Electric—transmission and distribution	5-75	N/A	5-75	5-65
Electric—generation	5-62	5-62	N/A	N/A
Gas	5-85	N/A	N/A	5-85
Common—electric and gas	5-46	N/A	N/A	5-46

Average Service Life in Years by Asset Category	Exelon	Generation	ComEd	PECO
2004
Electric—transmission and distribution	5-75	N/A	5-75	5-65
Electric—generation	5-63	5-63	N/A	N/A
Gas	5-85	N/A	N/A	5-85
Common—electric and gas	5-46	N/A	N/A	5-46

187

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Average Service Life Percentage by Asset Category	Exelon		Generation		ComEd		PECO
2006
Electric—transmission and distribution (a)	2.95	%	N/A		3.34	%	2.01	%
Electric—generation	3.18	%	3.18	%	N/A		N/A
Gas (a)	1.73	%	N/A		N/A		1.73	%
Common—electric and gas (a)	6.04	%	N/A		N/A		6.04	%
Average Service Life Percentage by Asset Category	Exelon		Generation		ComEd		PECO
2005
Electric—transmission and distribution	3.05	%	N/A		3.44	%	2.11	%
Electric—generation	3.50	%	3.50	%	N/A		N/A
Gas	2.32	%	N/A		N/A		2.32	%
Common—electric and gas	8.06	%	N/A		N/A		8.06	%
Average Service Life Percentage by Asset Category	Exelon		Generation		ComEd		PECO
2004
Electric—transmission and distribution	3.08	%	N/A		3.49	%	2.14	%
Electric—generation	3.26	%	3.26	%	N/A		N/A
Gas	2.52	%	N/A		N/A		2.52	%
Common—electric and gas	4.60	%	N/A		N/A		4.60	%

(a) With respect to PECO, the decrease in depreciation percentages from 2005 to 2006 reflects extensions of service lives for significant property, plant and equipment resulting from the latest depreciation study for which results were implemented during 2006.

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 19—Supplemental Financial Information for further information regarding Generation’s nuclear fuel, Generation’s asset retirement obligation, Generation’s intangible assets and the amortization of ComEd’s and PECO’s regulatory assets.

Nuclear Generating Station Decommissioning (Exelon and Generation)

Exelon and Generation account for the costs of decommissioning Generation’s nuclear generating stations in accordance with FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). To estimate the fair value of its obligation, Generation uses a probability-weighted, discounted cash flow model which considers multiple outcome scenarios based upon significant estimates and assumptions, including decommissioning cost studies, cost escalation studies, probabilistic cash flow models and discount rates. See Note 13—Asset Retirement Obligations for information regarding the application of SFAS No. 143.

Capitalized Interest and Allowance for Funds Used During Construction (Exelon, Generation, ComEd and PECO)

Exelon and Generation apply SFAS No. 34, “Capitalization of Interest Cost,” to calculate the costs during construction of debt funds used to finance non-regulated construction projects.

188

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon, ComEd and PECO apply SFAS No. 71 to calculate the allowance for funds used during construction (AFUDC), which 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 19—Supplemental Financial Information).

The following table summarizes total cost incurred, capitalized interest and credits of AFUDC by year:

		Exelon		Generation		ComEd		PECO
2006	Total incurred interest (a)	$	914	$	180	$	317	$	269
	Capitalized interest		22		21		—		—
	Credits to AFUDC debt and equity		15		—		12		3
2005	Total incurred interest (a)		844		140		297		281
	Capitalized interest		12		12		—		—
	Credits to AFUDC debt and equity		10		—		7		3
2004	Total incurred interest (a)		840		114		369		304
	Capitalized interest		11		11		—		—
	Credits to AFUDC debt and equity		5		—		3		2

(a) Includes interest expense to affiliates.

Guarantees (Exelon, Generation, ComEd and PECO)

In accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others (FIN 45),” the Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have 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 the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the Registrant’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. See Note 2—Acquisitions and Dispositions and Note 18—Commitments and Contingencies for further information.

Asset Impairments (Exelon, Generation, ComEd and PECO)

Long-Lived Assets. The Registrants evaluate 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).

189

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

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.

Investments. Beginning in 2006, and in connection with the issuance of FSP 115-1, Generation considers all nuclear decommissioning trust fund investments in an unrealized loss position to be other-than-temporarily impaired. As a result of certain NRC restrictions, Generation is unable to demonstrate its ability and intent to hold the nuclear decommissioning trust fund investments through a recovery period and accordingly recognizes any unrealized holding losses immediately.

Prior to 2006, Exelon and Generation evaluated, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as well as their intent and ability to hold the investment to determine whether an investment was considered other-then-temporarily impaired. Exelon and Generation also considered specific adverse conditions related to the financial health of and business outlook for the investee. Once a decline in fair value was determined to be other-than-temporary, an impairment charge was recorded and a new cost basis was established.

See Note 9—Fair Value of Financial Assets and Liabilities for a description of the other-than-temporary impairments in the nuclear decommissioning trust funds determined in 2006 and 2005.

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 application of SFAS No. 142 and the results of goodwill impairment studies that have been performed, which include the $776 million and $1.2 billion goodwill impairment charges Exelon and ComEd recorded in 2006 and 2005, respectively.

Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

The Registrants may 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 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 prices. Additionally, Generation enters into energy-related derivatives for trading purposes. ComEd has derivatives related to one wholesale

190

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

contract and certain other contracts to manage the market price exposures to several wholesale contracts that extend into 2007, which is beyond the expiration of ComEd’s PPA with Generation. The supplier forward contracts that ComEd has entered into as part of the initial ComEd procurement auction (See Note 4—Regulatory Issues) are deemed to be derivatives that qualify for the normal purchase exception to SFAS No. 133. ComEd does not enter into derivatives for speculative or trading purposes. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

The Registrants account 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. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the statement of cash flows, depending on the underlying nature of the Registrants’ hedged items. The majority of Generation’s derivatives are from hedges and therefore treated as operating cash flows. 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 and fuel or other, net on the Consolidated Statements of Operations.

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 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 were determined that a transaction designated as a “normal” purchase 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

191

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

ineffectiveness is recognized in earnings immediately. On an ongoing basis, the Registrants assess 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, Generation, ComEd and PECO)

The Registrants account for their 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.” Generation, ComEd and PECO participate in Exelon’s ongoing severance plans. Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 10—Severance Accounting for further discussion of Exelon’s accounting for severance benefits.

Retirement Benefits (Exelon, Generation, ComEd and PECO)

Exelon’s defined benefit pension plans and postretirement benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”, SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106), 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 SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158), 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) and SFAS No. 158. Generation, ComEd and PECO participate in Exelon’s defined benefit pension plans and postretirement plans. See Note 14—Retirement Benefits for further discussion of Exelon’s and Generation’s accounting for retirement benefits.

FSP FAS 106-2. Through Exelon’s postretirement benefit plans, the Registrants provide 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

192

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. The Registrants 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. Exelon’s annualized reduction in the net periodic postretirement benefit cost was approximately $40 million, $40 million and $33 million in 2006, 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 2006, 2005 and 2004 included in the consolidated financial statements and Note 14—Retirement Benefits was as follows:

	2006		2005		2004
Amortization of the actuarial experience loss	$	16	$	18	$	15
Reduction in current period service cost		9		8		6
Reduction in interest cost on the APBO		15		14		12

Treasury Stock (Exelon)

Treasury shares are recorded at cost. Any shares of common stock repurchased are held as treasury shares unless cancelled or reissued.

Foreign Currency Translation (Exelon, Generation and ComEd)

The financial statements of Exelon’s, Generation’s and 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 the Consolidated Balance Sheets and on weighted-average rates for the periods for the Consolidated Statements of Operations. Starting in 2006, ComEd does not report any foreign currency translation adjustments since ComEd no longer owns any foreign subsidiaries. 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.

New Accounting Pronouncements (Exelon, Generation, ComEd and PECO)

Exelon has identified the following new accounting pronouncements that either have been recently adopted or issued that may affect the Registrants upon adoption.

193

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

SFAS No. 123-R

Exelon grants stock-based awards through its Long-Term Incentive Plans (LTIPs), which primarily include stock options and performance share awards. Prior to January 1, 2006, Exelon accounted for these stock-based awards under the intrinsic value method of Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). This method under APB No. 25 resulted in no expense being recorded for stock option grants in 2005. On January 1, 2006, Exelon adopted Financial Accounting Standards Board (FASB) Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123) and supersedes APB No. 25. SFAS No. 123-R requires that compensation cost relating to stock-based payment transactions be recognized in the financial statements. That cost is measured on the fair value of the equity or liability instruments issued. SFAS No. 123-R applies to all of Exelon’s outstanding unvested stock-based awards as of January 1, 2006 and all prospective awards using the modified prospective transition method without restatement of prior periods. At December 31, 2006, there were approximately 28 million shares remaining for issuance under the LTIPs.

The following table shows the effect of adopting SFAS No. 123-R on selected reported items:

	Year Ended December 31, 2006
Income from continuing operations before income taxes and minority interest	$	(49	)
Net income		(31	)
Basic earnings per share		(0.05	)
Diluted earnings per share		(0.05	)
Cash flows provided by operating activities		(60	)
Cash flows used in financing activities		60

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income during the twelve months ended December 31, 2006, 2005 and 2004:

	Year Ended December 31,
Components of Stock-Based Compensation Expense	2006			2005			2004
Stock options	$	39		$	—		$	—
Performance shares		84			49			51
Other stock-based awards		5			8			14
Total stock-based compensation included in operating and maintenance expense		128			57			65
Income tax benefit		(48	)		(23	)		(26	)
Total after-tax stock-based compensation expense	$	80		$	34		$	39

194

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents stock-based compensation expense (pre-tax) during the twelve months ended December 31, 2006, 2005 and 2004:

	Year Ended December 31,
Registrant	2006		2005		2004
Generation	$	48	$	21	$	22
ComEd		12		2		3
PECO		3		1		1
Exelon Corporate (a)		65		33		39

(a) Represents amounts billed to Exelon’s subsidiaries through intercompany allocations.

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock are granted 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. Stock options granted under the LTIPs generally become exercisable upon a specified vesting date. Shares subject to stock options are typically issued from authorized but unissued common stock shares. All stock options expire ten years from the date of grant. The vesting period of stock options outstanding as of December 31, 2006 generally ranged from three years to four years. The value of stock options at the date of grant is either amortized through expense or capitalized over the requisite service period using the straight-line method. For stock options granted to retirement eligible employees, the value of the stock option is recognized immediately on the date of grant. There were no significant stock-based compensation costs capitalized during the twelve months ended December 31, 2006, 2005 and 2004.

Exelon grants most of its stock options in the first quarter of each year. Stock options granted during the remaining quarters of 2006, 2005 and 2004 were not material.

The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model with the following weighted average assumptions used for grants for the twelve months ended December 31, 2006, 2005 and 2004:

	Year Ended December 31,
	2006		2005		2004
Dividend yield	3.2	%	3.6	%	3.3	%
Expected volatility	25.5	%	18.1	%	19.7	%
Risk-free interest rate	4.27	%	3.83	%	3.25	%
Expected life (years)	6.25		6.25		5.0

The dividend yield is based on several factors, including Exelon’s most recent dividend payment at the grant date and the average stock price over the previous twelve months. Expected volatility is based on implied volatilities of traded stock options in Exelon’s common stock and historical volatility

195

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. The expected life represents the period of time the stock options are expected to be outstanding and is based on the “simplified method”. Additionally, Exelon uses historical data to estimate employee forfeitures. Exelon reviews the actual and estimated forfeitures on an annual basis and records an adjustment if necessary.

Utilizing the Black-Scholes-Merton option-pricing model and the assumptions discussed above, the weighted average grant-date fair value of stock options granted during the twelve months ended December 31, 2006, 2005 and 2004 was $13.22, $6.33 and $4.79, respectively.

Information with respect to stock options at December 31, 2006 is as follows:

	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2005	21,674,270		$	31.23
Options granted	4,084,645			58.55
Options exercised	(5,900,095	)		29.06
Options forfeited/cancelled	(483,710	)		42.40
Balance of shares outstanding at December 31, 2006	19,375,110			37.35	6.74	$	475,397,402
Exercisable at December 31, 2006 (a)	8,836,049			31.18	5.39		271,355,375

(a) Includes stock options issued to retirement-eligible employees.

Intrinsic value for stock-based instruments is defined as the difference between the current market value and the exercise price. The total intrinsic value of stock options exercised during the twelve months ended December 31, 2006, 2005 and 2004 was $170 million, $191 million and $102 million, respectively.

During the twelve months ended December 31, 2006, cash received from stock options exercised was $171 million, and the actual tax benefit realized for tax deductions from stock options exercised was $68 million. SFAS No. 123-R requires the benefits of tax deductions in excess of the compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. There was $53 million of excess tax benefits related to stock options exercised included as a cash inflow in other financing activities in Exelon’s Consolidated Statement of Cash Flows for the twelve months ended December 31, 2006. Prior to the adoption of SFAS No. 123-R, Exelon presented these benefits as operating cash flows in the Consolidated Statement of Cash Flows.

196

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table summarizes Exelon’s nonvested stock option activity for the twelve months ended December 31, 2006:

	Shares		Weighted Average Exercise Price (per share)
Nonvested at December 31, 2005	12,000,284		$	35.42
Granted	4,084,645			58.55
Vested	(5,071,953	)		38.35
Forfeited	(473,915	)		43.63
Nonvested at December 31, 2006	10,539,061			38.56

As of December 31, 2006, $44 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of two years. The total grant date fair value of stock options vested, including the capitalized amount, during the twelve months ended December 31, 2006, 2005 and 2004 was $41 million, $23 million and $34 million, respectively.

Performance Share Awards

In addition to the stock options discussed above, Exelon grants performance share awards under the LTIPs. These performance share awards will generally vest and settle over a three-year period. The holders of the performance share awards will receive shares of common stock and/or cash annually during the vesting period. The combination of common stock and/or cash is based on certain stock ownership requirements.

In January 2006, the Compensation Committee of the Board of Directors of Exelon granted 1,106,919 performance share awards, of which Exelon estimates that 601,306 will be settled in common stock and 505,613 will be settled in cash.

Performance share awards to be settled in stock are fair valued at the date of grant. Performance share awards to be settled in cash are remeasured each reporting period throughout the vesting period. As a result, the compensation costs for cash settled awards are subject to variability. The fair value of each performance share award granted during the twelve months ended December 31, 2006 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year. This model requires assumptions regarding Exelon’s total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon’s common stock and all stocks represented in these indices. Expected volatility is based on historical information. Additionally, Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted if necessary.

For non retirement-eligible employees, stock-based compensation costs are accrued and recognized over the vesting period of three years using the graded vesting method. As a result of

197

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

adopting SFAS No. 123-R, Exelon recognizes ratably throughout the year of grant the entire compensation cost of new common stock awards in which retirement-eligible employees are fully vested in the year of grant (non-substantive vesting approach). Prior to the adoption of SFAS No. 123-R on January 1, 2006, such compensation cost was recognized over the nominal vesting period of performance with any remaining compensation cost recognized at the date of retirement. The impact of using the non-substantive vesting approach for retirement-eligible employees related to performance share awards was $10 million during 2006.

During the twelve months ended December 31, 2006, Exelon settled 436,660 and 407,073 performance share awards in common stock and cash, respectively, related to awards granted prior to 2006. Exelon paid $24 million in cash during 2006 to settle the 407,073 performance share awards.

At December 31, 2006, Exelon had an obligation related to outstanding awards not yet settled of $95 million, of which $38 million, $27 million and $30 million are included in current liabilities, deferred credits and other liabilities, and common stock, respectively, in Exelon’s Consolidated Balance Sheet. At December 31, 2005, Exelon had an obligation related to outstanding awards not yet settled of $51 million, of which $27 million is included in common stock and $24 million is included in deferred credits and other liabilities in Exelon’s Consolidated Balance Sheet.

SFAS No. 123-R requires the benefits of tax deductions in excess of the compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. There was $7 million of excess tax benefits related to performance share awards exercised included as a cash inflow in other financing activities in Exelon’s Consolidated Statement of Cash Flows for the twelve months ended December 31, 2006. Prior to the adoption of SFAS No. 123-R, Exelon presented these benefits as operating cash flows in the Consolidated Statement of Cash Flows.

Other Stock-Based Awards

Exelon also issues common stock through an employee stock purchase plan and through restricted stock units and accounts for these awards in accordance with SFAS No. 123-R. The compensation cost of these types of issuances was immaterial during the twelve months ended December 31, 2006 and 2005. However, at December 31, 2006 and 2005, Exelon had obligations related to outstanding restricted stock not yet settled of $13 million and $19 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets.

Prior to January 1, 2007, directors and executives were able to defer stock awards granted to them through Exelon’s stock-based compensation programs into the Exelon Corporation Stock Deferral Plan. At December 31, 2006 and 2005, Exelon had an obligation related to this plan of $37 million and $30 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets.

198

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

2005 and 2004 Pro Forma Information

The table below shows 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 for the twelve months ended December 31, 2005 and 2004:

	Year Ended December 31, 2005			Year Ended December 31, 2004
Net income—as reported	$	923		$	1,864
Add: Stock-based compensation expense included in reported net income, net of income taxes		34			39
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes (a)		(48	)		(60	)
Pro forma net income	$	909		$	1,843
Earnings per share:
Basic—as reported	$	1.38		$	2.82
Basic—pro forma		1.36			2.79
Diluted—as reported		1.36			2.78
Diluted—pro forma		1.35			2.75

(a) The fair value of stock options granted was estimated using a Black-Scholes-Merton option-pricing model.

SFAS No. 155

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments, amendment of FASB Statements No. 133 and 140” (SFAS No. 155). SFAS No. 155 gives entities the option of applying fair value accounting to certain hybrid financial instruments in their entirety if they contain embedded derivatives that would otherwise require bifurcation under SFAS No. 133. SFAS No. 155 was effective for the Registrants as of January 1, 2007. The adoption of this standard did not have a material impact on the Registrants.

FSP FIN 46(R)-6

In April 2006, the FASB issued FSP FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FSP 46(R)-6). This pronouncement provides guidance on how a reporting enterprise should determine the variability to be considered in applying FIN 46-R, which could impact the assessment of whether certain variable interest entities are consolidated. FSP 46(R)-6 was effective for the Registrants on July 1, 2006. The adoption of this standard did not have a material impact on the Registrants in 2006. As the provisions of FSP 46(R)-6 are applied prospectively, the impact to the Registrants cannot be determined until the transactions occur.

199

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

FIN 48

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 applies to all income tax positions taken on previously filed tax returns or expected to be taken on a future tax return. FIN 48 prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold for purposes of applying FIN 48. Therefore, if it can be established that the only uncertainty is when an item is taken on a tax return, such positions have satisfied the recognition step for purposes of FIN 48 and uncertainty related to timing should be assessed as part of measurement. FIN 48 also requires that the amount of interest expense and income to be recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return.

FIN 48 was effective for the Registrants as of January 1, 2007. The change in net assets as a result of applying this pronouncement will be a change in accounting principle with the cumulative effect of the change required to be treated as an adjustment to the opening balance of retained earnings. Adjustments to goodwill or regulatory accounts associated with the implementation of FIN 48 will be based on other applicable accounting standards. The Registrants have not fully completed the process of evaluating the impact of adopting FIN 48, including the apportionment of the tax and interest impacts to the Registrants in Exelon’s affiliated group. Nevertheless, the Registrants have performed procedures to identify a range of the anticipated impacts of the adoption of FIN 48. The adoption of FIN 48 is not anticipated to have a material impact on the Registrants’ January 1, 2007 balance of retained earnings. The estimated impact of the adoption of FIN 48 on the Registrants’ financial statements is subject to change due to potential changes in interpretation of FIN 48 by the FASB and other regulatory bodies and the finalization of the Registrants’ adoption efforts.

EITF 06-3

In June 2006, the FASB ratified EITF Issue No. 06-3, “How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross Versus Net Presentation)” (EITF 06-3). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. In addition, EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis as well as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. EITF 06-3 will be effective for the Registrants as of January 1, 2007. The

200

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Registrants disclose taxes that are imposed on and concurrent with a specific revenue-producing transaction in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Exelon’s, ComEd’s and PECO’s utility taxes are presented on a gross basis (see Note 19—Supplemental Financial Information and Note 20—Segment Information). As EITF 06-3 provides only disclosure requirements, the adoption of this standard did not have a material impact on the Registrants.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements but does not change the requirements to apply fair value in existing accounting standards. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. SFAS No. 157 will be effective for the Registrants as of January 1, 2008 and the Registrants are currently assessing the impact that SFAS No. 157 may have on their financial statements.

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)”, which was effective for the Exelon and Generation as of December 31, 2006. SFAS No. 158 requires Exelon and Generation to recognize the overfunded or underfunded status of its defined benefit postretirement plans as an asset or liability on its balance sheet. The adoption of this standard did not materially impact the Registrants’ debt or credit agreement covenants. SFAS No. 158 also prescribes the measurement date of a plan to be the date of its year-end balance sheet, which is the measurement date Exelon and Generation already use for their plans. In addition, Exelon and Generation are required to disclose additional information about certain effects on net periodic benefit cost for the next fiscal year. See Note 14—Retirement Benefits for additional information. ComEd and PECO were not impacted by SFAS No. 158.

SAB No. 108

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (SAB No. 108) regarding the quantification of financial statement misstatements. SAB No. 108 requires a “dual approach” for quantifications of errors using both a method that focuses on the income statement impact, including the cumulative effect of prior years’ misstatements, and a method that focuses on the period-end balance sheet. SAB No. 108 will be effective for the Registrants as of January 1, 2007. The adoption of this standard did not have a material impact on the Registrants.

201

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Cumulative Effect of Changes in Accounting Principles

FIN 47. In March 2005, the FASB issued FIN 47, which clarifies that the term “conditional asset retirement obligation” as used in 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 the Registrants as of December 31, 2005. See Note 13—Asset Retirement Obligations for further information. The following table shows the charge the Registrants recorded as a cumulative effect of a change in accounting principle pursuant to the adoption of FIN 47 in 2005.

	Exelon		Generation		ComEd		PECO
Charge recorded, net of tax	$	42	$	30	$	9	$	3
Related tax impact		27		19		6		2

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.

FIN 46-R. See discussion of the adoption of FIN 46-R within the “Variable Interest Entities” discussion above.

202

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables set forth Exelon’s net income and basic and diluted earnings per common share for the years ended December 31, 2005 and 2004, adjusted as if FIN 46-R, EITF 03-16, and FIN 47 had been applied during those periods. FIN 46-R, EITF 03-16 and FIN 47 had adoption dates of March 31, 2004, July 1, 2004, and December 31, 2005, respectively.

	2005			2004
Reported income before cumulative effect of changes in accounting principles	$	965		$	1,841
Pro forma earnings effects (net of income taxes):
FIN 47		(5	)		(4	)
EITF 03-16		—			(1	)
Pro forma income before cumulative effect of changes in accounting principles	$	960		$	1,836
Reported net income	$	923		$	1,864
Pro forma earnings effects (net of income taxes):
FIN 47		(5	)		(4	)
EITF 03-16		—			(1	)
Reported cumulative effects of changes in accounting principles:
FIN 47		42			—
EITF 03-16		—			9
FIN 46-R		—			(32	)
Pro forma net income	$	960		$	1,836
	2005			2004
Basic earnings per common share:
Reported income before cumulative effect of changes in accounting principles	$	1.44		$	2.79
Pro forma income before cumulative effect of changes in accounting principles		1.43			2.78
Reported net income		1.38			2.82
Pro forma net income		1.43			2.78
	2005			2004
Diluted earnings per common share:
Reported income before cumulative effect of changes in accounting principles	$	1.42		$	2.75
Pro forma income before cumulative effect of changes in accounting principles		1.42			2.74
Reported net income		1.36			2.78
Pro forma net income		1.42			2.74

203

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables set forth Generation’s net income for the years ended December 31, 2005 and 2004, adjusted as if FIN 46-R and FIN 47 had been applied during those periods. FIN 46-R and FIN 47 had adoption dates of March 31, 2004 and December 31, 2005, respectively.

	2005			2004
Reported income before cumulative effect of changes in accounting principles	$	1,128		$	641
Pro forma earnings effects (net of income taxes):
FIN 47		(4	)		(4	)
Pro forma income before cumulative effect of changes in accounting principles	$	1,124		$	637
Reported net income	$	1,098		$	673
Pro forma earnings effects (net of income taxes):
FIN 47		(4	)		(4	)
Reported cumulative effects of changes in accounting principles:
FIN 47		30			—
FIN 46-R		—			(32	)
Pro forma net income	$	1,124		$	637

The adoption of these standards did not have a material impact on the historical income statements of ComEd and PECO.

2. Acquisitions and Dispositions (Exelon and Generation)

Termination of Proposed Merger with PSEG (Exelon)

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), a public utility holding company primarily located and serving customers in New Jersey, whereby PSEG would have been merged with and into Exelon (Merger). All regulatory approvals or reviews necessary to complete the Merger had been completed with the exception of the approval from the New Jersey Board of Public Utilities (NJBPU). On September 14, 2006, Exelon gave formal notice to PSEG that Exelon had terminated the Merger Agreement and the companies agreed to withdraw their application for Merger approval, which had been pending before the NJBPU for more than 19 months. Exelon also terminated pending dockets and/or appeals in numerous other jurisdictions, including before the FERC and the Antitrust Division of the United States Department of Justice. See Note 4—Regulatory Issues for information regarding PECO’s proposed partial settlement before the PAPUC.

Exelon capitalized certain external costs associated with the Merger since the execution of the Merger Agreement on December 20, 2004. As required under GAAP, Exelon recorded Merger-related expenses of approximately $93 million (pre-tax) in operating and maintenance expense on Exelon’s Consolidated Statement of Operations, of which $55 million ($35 million after tax) was recorded in the third quarter of 2006 to write off the capitalized costs associated with the Merger. Including this $93 million of expenses, total Merger-related expenses incurred since the inception of the Merger discussions were approximately $130 million. Total capitalized costs of $46 million were included in deferred debits and other assets on Exelon’s Consolidated Balance Sheets as of December 31, 2005.

204

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Disposition of Enterprises Entities (Exelon)

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 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 $60 million and $8 million, respectively. A pre-tax impairment charge of $5 million related to Exelon Services’ tangible assets was recorded in 2004. As of December 31, 2006 and 2005, Exelon Services had remaining assets of $52 million and $51 million, respectively, and liabilities of $5 million and $5 million, respectively, which primarily consisted of tax assets, affiliate receivables and payables, and sales proceeds to be collected.

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 Operations.

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 would have resulted in certain payments to InfraSource if the amount of services Exelon purchases from InfraSource during the period from closing through 2006 were below specified thresholds. All specified thresholds were met or exceeded. Due to Exelon’s 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 Operations.

205

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 Operations. See Note 3—Discontinued Operations for additional information.

Investments in Synthetic Fuel-Producing Facilities (Exelon)

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 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 was amortized as the tax credits were earned; however, Exelon recorded an impairment charge to fully impair this intangible asset in the second quarter of 2006.

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 was amortized as these tax credits are earned; however, Exelon recorded an impairment charge to fully impair this intangible asset in the second quarter of 2006.

See Note 12—Income Taxes for additional information regarding Exelon’s investments in synthetic fuel-producing facilities.

Investments in Affordable Housing (Exelon)

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 of Southeast Chicago Energy Project, LLC (SCEP) (Exelon and Generation)

Generation and Peoples Calumet, LLC (Peoples Calumet), a subsidiary of Peoples Energy Corporation, were joint owners of SCEP, a 350-megawatt natural gas-fired, peaking electric power plant located in Chicago, Illinois, which began operation in 2002. In 2002, Generation and Peoples Calumet owned 70% and 30%, respectively, of SCEP. Pursuant to the joint owners agreement, Generation was obligated to purchase Peoples Calumet’s 30% interest ratably over a 20-year period.

206

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation had reflected the third-party interest in this majority-owned investment as a long-term liability in its consolidated financial statements. On March 31, 2006, Generation entered into an agreement to accelerate the acquisition of Peoples Calumet’s interest in SCEP. This transaction closed on May 31, 2006. Under the agreement, Generation paid Peoples Calumet approximately $47 million for its remaining interest in SCEP. Generation financed this transaction using short-term debt and available cash.

Acquisition and Disposition of Sithe Energies, Inc. (Sithe) (Exelon and Generation)

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 and 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. In connection with the sale, Exelon recorded $55 million of liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. Generation issued certain guarantees associated with income tax indemnifications to Dynegy in connection with the sale that were valued at approximately $8 million (included in the $55 million accrual discussed above), of which $7 million had expired as of December 31, 2006. 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 remaining exposures covered by these indemnities are anticipated to expire in 2007 and beyond. 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, 2006, Exelon’s accrued liabilities related to these indemnifications and guarantees were $42 million, including $1 million related to income tax indemnifications. The net decrease for the accrual initially established was due to the expiration of certain guarantees, tax indemnifications and accrued interest on certain indemnifications. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $175 million at December 31, 2006.

Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income for 2006, 2005 and 2004, included the following financial results related to Sithe:

	2006			2005 (a)			2004 (b)
Operating revenues	$	—		$	30		$	248
Operating income		—			5			1
Net income (loss)		4	(d)		18	(c)		(27	)

(a) Sithe was sold on January 31, 2005. Accordingly, results include only one month of operations.

(b) Results include Exelon and 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 3—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 Operations.

207

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

(c) Net income for 2005 included a pre-tax gain on sale of Sithe of $24 million.

(d) Net income for 2006 included a pre-tax gain on sale of Sithe as a result of the expiration of certain tax indemnifications and the collection of a receivable arising from the sale of Sithe that had been fully reserved.

Acquisition of Sithe International, Inc. Tamuin International, Inc. (TII), a wholly owned subsidiary of Generation (formerly Sithe International, Inc.), through its subsidiaries, has 49.5% interests in two Mexican business trusts that own the Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (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.

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. 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.

Consolidation of Sithe as of March 31, 2004. 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.

Sale of TEG and TEP. On November 6, 2006, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, entered into a purchase and sale agreement to sell its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation (AES) for $95 million in cash plus certain purchase price adjustments. This transaction closed on February 9, 2007 and is not expected to have a material impact on net income. In connection with the transaction, Generation entered into a guaranty agreement under which Generation guarantees the timely payment of TII’s obligations to the subsidiary of AES expressly covered under the purchase and sale agreement. Generation would be required to perform in the event that TII does not pay any obligation covered by the guaranty that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guaranty is $95 million. Generation has not recorded a liability associated with this guaranty. The exposures covered by this guaranty are anticipated to expire in the second half of 2008 and beyond.

Sale of Ownership Interest in Boston Generating, LLC (Exelon and Generation)

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).

208

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. 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.

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 and 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, Exelon and Generation recorded a gain of $85 million ($52 million net of income taxes) in other income and deductions within the Consolidated Statements of Operations in the second quarter of 2004.

In connection with the sale, Exelon and 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, 2006, 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 and Generation’s Consolidated Statements of Operations. See Note 18—Commitments and Contingencies for further information regarding the guarantee.

Exelon and Generation’s Consolidated Statements of Operations include the following results related to Boston Generating:

	2004
Operating revenues	$	248
Operating loss		(49	)
Net income (a)		21

(a) 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.

3. Discontinued Operations (Exelon and Generation)

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. See Note 2—Acquisitions and Dispositions for additional information regarding the disposition of Sithe. In addition, during 2003 and 2004, Exelon sold or wound down substantially all components of Exelon Enterprises Company, LLC (Enterprises). As a result, the results of operations and any gain or loss on the sale of these entities are presented as discontinued operations for 2006, 2005 and 2004, within Exelon’s (for Sithe and Enterprises) and Generation’s (for

209

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Sithe) Consolidated Statements of Operations and Comprehensive Income. Results related to these entities were as follows:

2006	Sithe (a)		Enterprises			AllEnergy		Total
Total operating revenues	$	—	$	(1	)	$	—	$	(1	)
Operating loss		—		(2	)		—		(2	)
Income (loss) before income taxes and minority interest		6		(2	)		—		4

(a) Net income for 2006 included a pre-tax gain on the sale of Sithe as a result of the expiration of certain tax indemnifications and the collection of a receivable arising from the sale of Sithe that had been fully reserved.

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 2—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 2—Acquisitions and Dispositions for further information regarding the sale of Sithe.

(b) Excludes certain investments.

For the year ended December 31, 2006, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income included $4 million of income (after tax) from discontinued operations related to Sithe, which represented an adjustment to the gain on sale as a result of the expiration of certain tax indemnifications, accrued interest on an indemnification and the collection of a receivable arising from the sale of Sithe that had been fully reserved.

4. Regulatory Issues (Exelon, Generation, ComEd and PECO)

The legislatively mandated transition and rate freeze period in Illinois ended in January 2007. Associated with the end of this rate freeze, ComEd is engaged in various regulatory and legislative proceedings to establish rates for the post-2006 period, which are more fully described below.

Illinois Procurement Case (Exelon and ComEd). On February 25, 2005, ComEd made a filing with the ICC to seek regulatory approval of tariffs that would authorize ComEd to bill its customers for electricity costs incurred under a reverse-auction competitive bidding process (the Procurement Case). On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of electricity by ComEd after the end of the transition period. This approval, currently under appeal before the Illinois Appellate Court, should provide ComEd with stability and greater certainty that it will be able to procure energy through the auction process and pass through the

210

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

costs of that energy to ComEd’s customers through a transparent market mechanism. The energy price that resulted from the first auction is locked in until June 2008. The reverse-auction competitive bidding process is administered by an independent auction manager, with oversight by the ICC staff. On December 6, 2006, the ICC staff released its report on the auction, which generally spoke favorably of the process and the outcome. The report recommended the continued use of the reverse-auction for future electric power procurement. In order to mitigate the effects of changes in future prices, electricity to serve residential and commercial customers with loads less than 400kW will be procured through staggered contracts.

The ICC will subsequently review on an annual basis the prudence of ComEd’s electricity purchases, but compliance with the ICC-approved reverse-auction process will establish a rebuttable presumption of prudence. Various parties, including governmental and consumer representatives and ComEd, have filed petitions for review of portions of the order with the Illinois Appellate Court. While ComEd is generally supportive of the order in the Procurement Case, ComEd has objected to the requirement for an after-the-fact prudence review. On June 2, 2006, the Illinois Attorney General filed a petition with the Illinois Supreme Court asking the Supreme Court to hear the matter on direct appeal, to grant expedited review of the pending appeals, and to stay implementation of the auction pending appeal. On August 4, 2006, the Illinois Supreme Court denied this petition. The Illinois Attorney General filed a petition with the Illinois Appellate Court asking for a stay of implementation of the ICC order in the Procurement Case pending the Illinois Appellate Court’s decision on the appeals. That request was denied on August 23, 2006. On December 29, 2006, the Illinois Appellate Court denied the Illinois Attorney General’s request for a stay of implementation of the ICC order in the Procurement Case. On January 11, 2007, the Illinois Supreme Court denied the Illinois Attorney General’s motion for a stay. The appeals before the Illinois Appellate Court are still pending.

Initial ComEd Auction (Exelon and ComEd). The first procurement auction for ComEd’s entire load took place during September 2006 for electricity to be delivered beginning in January 2007. Auction participants bid on several different products including 17-, 29- and 41-month contracts that will be “blended” together and used to serve residential and small commercial customers, a 17-month “annual” product that will be used to serve larger non-residential customers, and a variably priced “hourly” product that would be used to serve customers who either select hourly service or are not eligible to receive fixed price service. The ICC accepted the auction results related to the blended and annual products but rejected the auction results for the hourly product. Under ComEd’s tariffs, electricity that would have been procured through the hourly auction is currently being purchased in the PJM Interconnection, LLC (PJM) administered wholesale electricity markets.

ComEd has entered into supplier forward contracts with all of those who have won shares of the ComEd products through the auction. Suppliers were limited to winning no more than 35% in either the fixed price section or the hourly price section of the auction (for either the ComEd or the Ameren Corporation (Ameren) auctions). In the ComEd auction, Generation won 35% of the fixed price auction. The following table presents the clearing prices for each product set in the first auction for ComEd:

	Price per MWh
Product	17-month contract		29-month contract		41-month contract
Annual	$	90.12		N/A		N/A
Blended	$	63.96	$	64.00	$	63.33

211

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents the tranches won by each supplier for the ComEd auction. Suppliers won bids for tranches or “slices” of electricity and are required to supply a fixed percentage of the total load regardless of that level of load. Each supplier is required to provide a variable quantity of power based on the tranches won.

Suppliers	Annual Product 17- month contract	Blended Product 17- month contract	Blended Product 29- month contract	Blended Product 41- month contract
American Electric Power Service Corporation	5	3	—	—
Conectiv Energy Supply, Inc.	3	—	6	1
Constellation Energy Commodities Group, Inc.	22	—	3	—
DTE Energy Trading, Inc	3	3	4	—
Edison Mission Marketing & Trading, Inc	—	19	22	—
Energy America, LLC	—	4	—	—
Exelon Generation Company, LLC	1	—	38	89
FPL Energy Power Marketing, Inc	9	6	—	—
J. Aron & Company	—	15	10	—
J.P. Morgan Ventures Energy Corporation	—	27	4	1
Morgan Stanley Capital Group, Inc	37	6	—	—
PPL EnergyPlus, Inc	—	6	6	2
Sempra Energy Trading Corp	8	—	—	—
WPS Energy Services, Inc	—	3	—	—
	88	92	93	93

The next auction is scheduled for January 2008 for the period June 2008 through May 2009 (and up to May 2011 for portions of the blended product). Auctions will be held annually thereafter covering the next June to May twelve-month and thirty-six-month periods.

Rate Freeze Extension Proposal (Exelon and ComEd). On February 24, 2006, House Bill 5766 (HB 5766) was introduced in the Illinois General Assembly and was referred to the Rules Committee. HB 5766, if enacted, would extend the transition period rate freeze in Illinois until at least 2010. On October 9, 2006, an amendment was filed to Senate Bill 1714 (SB 1714), which was substantively the same as HB 5766, and the House Electric Utility Oversight Committee, by a 9 to 4 vote, with one member voting present, approved the amendment to SB 1714. Various similar bills and amendments followed, as did “compromise” legislation that would not freeze rates but would mandate interest-free phase-ins of the increases and require contributions of $33 million for customer assistance, renewable energy and efficiency programs. Rate freeze legislation, which was amended to include a rollback of rates to 2006 levels and was strongly supported by the Speaker of the Illinois House of Representatives (House), was passed by the House on January 7, 2007, but was not called for a vote in the Illinois Senate (Senate) before the end of that legislative session on January 9, 2007. The “compromise” legislation, strongly advocated by the Senate President and supported by the Senate and House minorities, was passed by the Senate in that legislative session, but it was not called for a vote in the House. That legislative session ended on January 9, 2007 without any legislation having passed both the House and the Senate. All legislation pending at the close of the legislative session on

212

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

January 9, 2007 expired. A new session is underway and legislation similar to previously proposed legislation has been reintroduced. ComEd is unable to predict the final disposition of any legislation that may be presented during 2007 to rollback rates, change the end of the mandated transition and rate freeze period in Illinois, or otherwise. ComEd believes a rate rollback and freeze, if enacted into law, would have serious detrimental effects on Illinois, ComEd and consumers of electricity. If legislation similar to the “compromise” bill previously passed by the Senate to phase-in the rate increases is enacted, there would be material adverse effects on Exelon’s and ComEd’s results of operations and cash flows as the “compromise” bill did not provide for the recovery of carrying charges. See “Post-2006 Summary” below for further detail. ComEd believes such legislation, if enacted into law, will violate Federal law and the U.S. Constitution, and ComEd is prepared to vigorously challenge any such legislation in court.

Residential Rate Stabilization Program (Exelon and ComEd). In a December 20, 2006 order, the ICC approved a program, proposed by ComEd, to mitigate the impact on ComEd’s residential customers of ComEd’s transition from almost a decade of reduced and frozen rates to rates that reflect the current cost of providing service. The program includes an “opt-in” feature to give residential customers the choice to participate in the program. Average annual residential electric rate increases would be capped at 10% in each of 2007, 2008 and 2009 for customers choosing to participate in the program. For those customers, costs that exceed the caps would be deferred and recovered over three years from 2010 to 2012. Deferred balances will be assessed an annual carrying charge of 3.25%. If ComEd’s rate increases are less than the caps in 2008 and 2009, ComEd would begin to recover deferred amounts up to the caps with carrying costs. The program would terminate upon a force majeure event, upon a ComEd bankruptcy, or if ComEd’s senior unsecured credit ratings from the three major credit rating agencies fall below investment grade. This order also strongly encouraged, but did not require, ComEd to make contributions to environmental and customer assistance programs—see “Renewable Energy Filings” below. This order is subject to rehearing and appeal.

Illinois Rate Case (Exelon and ComEd). On August 31, 2005, ComEd filed a rate case with the ICC to comprehensively review its tariff and to adjust ComEd’s rates for delivering electricity effective January 2007 (Rate Case). ComEd proposed a revenue increase of $317 million. The ICC staff and several intervenors in the Rate Case, including the Illinois Attorney General, suggested and provided testimony that ComEd’s rates for delivery services should be reduced. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC rate order in the Procurement Case. On June 8, 2006, the administrative law judges (ALJs) issued a proposed order recommending a revenue increase of $164 million which included ComEd’s request for recovery of several items that previously were recorded as expense. On July 26, 2006, the ICC issued its order in the Rate Case which approved a delivery services revenue increase of approximately $8 million of the $317 million proposed revenue increase requested by ComEd. The ICC order approved ComEd’s requested recovery of several items which previously were recorded as expense. However, the ICC disallowed rate base treatment (return) for ComEd’s prepaid pension asset and disallowed the recovery of certain administrative and general expenses. These disallowances did not result in an immediate write-off because the prepaid pension asset should be recovered as pension cost is recognized and recovered from customers in the future. The ICC rate order also provided for lower returns on rate base than ComEd had requested. See Note 18—Commitments and Contingencies for further information. The ICC subsequently granted in part requests for rehearing of

213

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd and various other parties. On December 20, 2006, the ICC issued an order on rehearing that increased the amount previously approved by approximately $74 million, including a partial return on the pension asset, for a total rate increase of $83 million. ComEd and various other parties have appealed the rate order to the courts. It is unlikely the appeal will be resolved until the second half of 2007 at the earliest. In the event the order is ultimately changed, the changes should be prospective only.

Real-Time Pricing Program (Exelon and ComEd). In 2006, the ICC approved a real-time pricing program which will offer residential customers an alternative to standard flat-rate utility billing. Starting in 2007, residential customers registered in the program will be able to control their electricity bills by using less power during higher-priced time periods.

Original Cost Audit (Exelon and ComEd). In the Rate Case, the ICC ordered an “original cost” audit of ComEd’s distribution assets. The ICC order did not find that any portion of ComEd’s delivery service assets should be disallowed because it was unreasonable in amount, imprudently incurred or not used and useful. The ICC rate order does not provide for a new review of these issues but instead provides that the ICC-appointed auditors determine whether the costs of ComEd’s distribution assets were properly recorded on ComEd’s financial statements at their original costs. The result of this audit will be addressed through a separately docketed proceeding. The original cost audit report is expected to be finalized in 2007 with an ICC proceeding to follow the issuance of the report. This proceeding may extend into 2008. ComEd is unable to predict the results of this audit but does not believe the results of the audit will have a material impact on ComEd’s financial position or results of operations.

Customers’ Affordable Reliable Energy (Exelon and ComEd). In July 2006, ComEd implemented Customers’ Affordable Reliable Energy (CARE), an initiative to help customers prepare for electricity rate increases coming in 2007 after the expiration of the rate freeze in Illinois. In addition to the residential rate stabilization program discussed above, CARE includes a variety of energy efficiency, low-income and senior citizen programs to help mitigate the impacts of the rate increase on customers’ bills. ComEd spent approximately $9 million for CARE in 2006.

Renewable Energy Filings (Exelon and ComEd). The ICC, in a January 24, 2006 order, ordered its staff to initiate three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources. These rulemakings have proceeded with ComEd’s active participation. On October 12, 2006, the ICC voted 5 to 0 to dismiss the three rulemaking proceedings.

On April 4, 2006, ComEd filed with the ICC a request for ICC approval to purchase and receive recovery of costs associated with the output of a portfolio of competitively procured wind resources of approximately 300 MW. The filing supports the ICC’s resolution of July 19, 2005 which endorsed the Illinois Governor’s proposal for a voluntary initiative in which electric suppliers would obtain resources equal to 2% of electricity sold to Illinois retail customers from renewable energy resources by the end of 2007 and gradually increasing to a target of 8% by 2013 (the Plan). This filing covers the first year’s wind-only procurement associated with the Plan. ComEd asked, and the ALJ agreed, to continue these proceedings until February 2007.

214

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

In the ICC’s December 20, 2006 order approving ComEd’s residential rate stabilization program, the ICC also strongly encouraged, but did not require, ComEd to make contributions totaling $30 million to environmental and customer assistance programs. ComEd is currently evaluating this request. ComEd has 60 days from the date of this order to file a proposal for the programs it plans to fund or implement. The ICC has 150 days to approve or modify the proposal. ComEd is currently evaluating the manner in which it may offer renewable energy programs at the ICC’s encouragement. ComEd has included energy efficiency and demand response programs as a part of its ComEd CARE initiative, sponsored to assist customers with mitigating impacts of higher prices beginning in 2007 and may undertake additional demand response, energy efficiency and renewable energy related initiatives in the future; however, such initiatives will likely be dependent on the resolution of other regulatory and legislative issues mentioned previously.

Post-2006 Summary (Exelon and ComEd). ComEd cannot predict the results of any rehearings or appeals in the Rate Case or the Procurement Case or whether the Illinois General Assembly might pass rate roll back and freeze legislation or take other action that could have a material effect on the outcome of the regulatory process. If the price which ComEd is ultimately allowed to bill to customers for electricity is below ComEd’s cost to procure and deliver electricity, ComEd expects that it will suffer adverse consequences, which could be material. Exelon and ComEd believe that these potential material adverse consequences could include, but may not be limited to, reduced earnings for Exelon and ComEd, further reduction of ComEd’s 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 may force ComEd to procure electricity at more volatile spot market prices, all of which could lead ComEd to seek protection through a bankruptcy filing. 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. Additionally, if ComEd’s ability to recover its costs from customers through rates is significantly affected, all or a portion of ComEd’s business could be required to cease applying SFAS No. 71, which covers the accounting for the effects of rate regulation and which would require Exelon and ComEd to eliminate the financial statement effects of regulation for the portion of ComEd’s business that ceases to meet the criteria. This would result in the elimination of all associated regulatory assets and liabilities that ComEd had recorded on its Consolidated Balance Sheets through the recording of a one-time extraordinary gain on its Consolidated Statements of Operations and Comprehensive Income (Loss). At December 31, 2006, the income statement gain could have been as much as $1.0 billion and $2.3 billion (before taxes) at Exelon and ComEd, respectively. Finally, the impacts and resolution of the above items could lead to an additional impairment of ComEd’s goodwill, which would be significant and at least partially offset the extraordinary gain discussed above. See Note 8—Intangible Assets for further information related to ComEd’s goodwill.

Return on Common Equity Threshold (Exelon and ComEd). Under Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeded 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.

215

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. ComEd has not triggered the earnings sharing provision through 2006. Beginning in 2007, this provision is no longer applicable to ComEd.

Delivery Service Rates (Exelon and ComEd). On March 3, 2003, ComEd entered into, and the ICC subsequently entered orders that implemented, 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 facilitated competitive service declarations for large-load customers and an extension of ComEd’s PPA with Generation. The effect of the Agreement was to lower competitive transition charge (CTC) collections that ComEd received from customers who took electricity from a competitive electric generation supplier or under the purchase power option (PPO) through 2006. The Agreement also allowed customers to lock in current CTCs for multiple years. ComEd collected $40 million, $105 million and $169 million in CTC revenues during 2006, 2005 and 2004, respectively. CTC collections ended with the transition on January 1, 2007.

Open Access Transmission Tariff (Exelon and ComEd). On November 10, 2003, 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 has not significantly increased operating revenues. As noted, both the rate freeze and CTCs ended in January 2007. During the third quarter of 2004, a settlement agreement was reached, which was approved by FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.

Partial Settlement before the PAPUC (Exelon and PECO). As a result of the termination of the Merger Agreement, the provisions of the PAPUC order and partial settlement approving the Merger will not become effective and will not be applicable to PECO or the other parties to the settlement.

Rate Limitations (Exelon and PECO). Pursuant to a settlement agreement with the PAPUC related to the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (PECO/Unicom Merger), 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 is subject to rate caps on its energy rates through December 31, 2010.

Through and Out (T&O) Rates and Seams Elimination Charge/Cost Adjustment/Assignment (SECA) (Exelon, ComEd and PECO). In November 2004, 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 T&O rates for transmission service scheduled out of, or across, their

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

respective transmission systems and ending within pre-expansion territories of PJM or Midwest Independent System Operators (MISO). T&O rates were terminated pursuant to FERC orders, effective December 1, 2004. The new rates, known as SECA, were collected from load-serving entities and paid to transmission owners 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 were also required to pay SECA rates during the transitional period based on the benefits they received from the elimination of T&O rates of other transmission owners within PJM and MISO. Since the inception of the SECA rates in December 2004, ComEd has recorded approximately $49 million of SECA collections net of SECA charges, including $5 million during the year ended December 31, 2006, while PECO has recorded $11 million of SECA charges net of SECA collections, including $4 million during the year ended December 31, 2006. Management of each of ComEd and PECO believes that appropriate reserves have been established in the event that some portion of SECA collections are required to be refunded. A hearing was held in May 2006 and the ALJ issued an initial decision on August 10, 2006. The ALJ’s initial decision indicated that the transmission owners overstated their lost revenues in their compliance filings and the SECA rate design was flawed. Additionally, the ALJ recommended that the transmission owners should be ordered to refile their respective compliance filings related to SECA rates. ComEd and PECO have filed exceptions to the initial decision and FERC, on review, will determine whether or not to accept the ALJ’s recommendation. There is no timeline for FERC to act on this matter. Settlements have been reached with various parties. FERC has approved several of these settlements while others are still awaiting final execution and/or FERC approval. The ultimate outcome of the proceeding establishing SECA rates is uncertain, but ComEd and PECO do not believe ultimate resolution of this matter will be material to the results of operations or financial position.

PJM Transmission Design (Exelon, ComEd and PECO). On May 31, 2005, FERC issued an order creating an evidentiary hearing process to examine the existing PJM transmission rate design. A number of parties submitted testimony proposing the replacement of that rate design for existing facilities with several variations which could have an adverse impact on Exelon’s pre-tax operating income. FERC staff submitted testimony opposing adoption of all of those variations, and in the alternative recommended that FERC supplant the existing design in which customers in a zone pay a transmission rate based on the cost of transmission in that zone, with a postage stamp rate design across PJM in which a single, uniform charge would be applied for all existing transmission facilities. This proposal, if adopted, would also be expected to produce an adverse impact on Exelon’s pre-tax operating income. ComEd and PECO, as members of the Responsible Pricing Alliance (comprised of most of the PJM transmission owners), submitted testimony opposing all changes and urging retention of the existing rate design at least through January 2008.

On July 13, 2006, the ALJ in the case issued an initial decision that recommends that FERC implement the postage stamp rate suggested by FERC staff, effective as of April 1, 2006, but also allows for the potential to phase in rate changes. On review of the matter, FERC will determine whether changes in rate design should be made, what those changes should be and their effective date. There is no set timeline for FERC to act on this matter. ComEd and PECO cannot predict how FERC will ultimately rule on this matter, including the effective date and if there would be any rates that may be subject to refund. ComEd and PECO also cannot estimate the final impact on either company’s

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

results of operations and cash flows. However, ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006 should be recoverable through retail rates. With the expiration of PECO’s transmission and distribution rate caps on December 31, 2006, PECO has the right to file with the PAPUC for a change in retail rates to reflect the impact of any change in wholesale transmission rates.

Customer Choice (Exelon, ComEd and PECO). All of ComEd’s retail customers are eligible to choose a competitive electric generation supplier and most non-residential customers may also buy electricity from ComEd at market-based prices under the PPO. One competitive electric generation supplier was granted approval to serve residential customers in the ComEd service territory. However, as of December 31, 2006, they are not currently supplying electricity to any of ComEd’s residential customers. As of December 31, 2006, approximately 20,300 non-residential customers, or 28% of ComEd’s annual retail kWh sales, had elected either the PPO or a competitive electric generation supplier. Customers who receive energy from a competitive electric generation supplier continue to pay a delivery charge.

All PECO customers may choose to purchase energy from a competitive electric generation supplier. As of December 31, 2006, approximately 34,400 customers, representing approximately 2% of PECO’s annual kWh sales, had elected to purchase their electric energy from a competitive electric generation supplier. Customers who receive energy from a competitive electric generation supplier continue to pay delivery charges and CTCs.

Initial Illinois Auction (Exelon and Generation). As described in the “Initial ComEd Auction” section above, Generation participated and won portions of the ComEd and Ameren auctions. The results and clearing prices of the ComEd auction are described above. In the Ameren auction, Generation won 10 tranches, or 27% of the annual 17-month product, with clearing prices of $84.95 per MWh.

Post-2006 Summary (Exelon and Generation). Generation’s PPA with ComEd expired at the end of 2006. In September 2006, Generation participated in and won portions of the ComEd and Ameren auctions. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation will sell more power through bilateral agreements with other new and existing counterparties. 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; therefore, Generation’s credit risk profile is anticipated to change based on the credit worthiness of the new and existing counterparties, including ComEd and Ameren. Additionally, due to the possibility of rate freeze legislation in Illinois affecting both ComEd and Ameren, Generation may be subject to the risk of default and, in the event of a bankruptcy filing by ComEd or Ameren, a risk that the bankruptcy may result in rejection of contracts for the purchase of power. A default by ComEd or Ameren on contracts for purchase of electricity, or a rejection of those contracts in a bankruptcy proceeding, could result in a disruption in the wholesale power markets.

Market-Based Rates Matters (Exelon and Generation). On July 5, 2005, FERC issued an order conditionally approving Exelon’s entities’ continued sales of power at market-based rates. As part of that order, FERC instituted a Section 206 proceeding on the basis that Exelon had not addressed the

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Commonwealth Edison Company and Subsidiary Companies

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

issue of affiliate abuse. On April 3, 2006, FERC terminated proceedings under Section 206, accepting Exelon’s statements that, under the regulatory structures in Illinois and Pennsylvania, most of the load is served under fixed prices and that no customer is captive, a scenario that had not changed since the previous market-based rates filing in 2000 and that alleviated concerns of affiliate abuse or reciprocal dealing.

On May 19, 2006, FERC issued a Notice of Proposed Rule Making (NOPR) on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities. The NOPR proposes a set of regulations that would modify the tests that Exelon and other market participants must satisfy to be entitled to market-based rates. Exelon currently expects that FERC will rule on the NOPR in the first or second quarter of 2007, and that Exelon will be required to make its first filing with the FERC under the new standards in the second quarter of 2007. Exelon is not certain as to the impact of any new rules that are promulgated as a result of FERC’s future ruling with respect to the NOPR.

On December 15, 2006, Exelon made a Change in Status (CIS) filing with FERC. The triggering event was the end of the full-requirements PPA between Generation and ComEd and the resulting increase in Generation’s uncommitted capacity. A CIS filing is required when there is a material change in status relied upon by FERC when granting market-based rates authority. Exelon’s filing, supported by an updated market-power analysis, demonstrated that Exelon continues to be entitled to market-based rates. The time period for interventions expired on January 5, 2007, no party intervened, and on February 9, 2007, FERC accepted Exelon’s CIS filing.

Reliability Pricing Model (RPM) (Exelon and Generation). On August 31, 2005, PJM filed its RPM with FERC to replace its current capacity market rules. The RPM proposal provided for a forward capacity auction using a demand curve and locational deliverability zones for capacity phased in over a several year period beginning on June 1, 2006. On November 5, 2005, PJM proposed to delay the effective date of the RPM until June 1, 2007. On April 20, 2006, FERC issued an order generally finding aspects of PJM’s RPM filing to be just and reasonable, but FERC also established further procedures to resolve the remaining issues and encouraged the parties to seek a negotiated resolution. A final settlement was filed with FERC on September 29, 2006 and FERC issued its order approving the settlement, subject to conditions, on December 22, 2006. FERC’s adoption of the settlement proposal of September 2006 is expected to have a favorable impact for owners of generation facilities, and particularly for such facilities located in constrained zones. The final revenue impact of the settlement on Generation, particularly over an extended time period, however cannot be estimated at this time.

FERC has also denied requests for rehearing of its April 20, 2006 order. The time for filing a petition for review of FERC’s April 2006 order will expire on February 20, 2007. In addition, FERC’s order approving the settlement, subject to conditions, is subject to requests for rehearing and judicial review. PJM will almost certainly implement RPM in 2007 notwithstanding, as FERC’s orders are rarely stayed, and therefore almost always remain in effect, pending appellate review. The first auction, which is scheduled to occur in April 2007, will allow Generation to better estimate the revenue impact for the period June 1, 2007 through May 31, 2008.

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The Energy Policy Act of 2005 (Exelon, Generation, ComEd and PECO). 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 the transmission infrastructure, streamline electric regulation, improve wholesale competition, address problems identified in the western energy crisis and the Enron Corporation 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 transferred to FERC certain additional authority. FERC was granted 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. Additionally, 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 required the creation of a self-regulating electric reliability organization with FERC oversight to enforce reliability rules. On July 20, 2006, pursuant to the Energy Policy Act, FERC certified the North American Electric Reliability Corporation (NERC) as the nation’s Electric Reliability Organization. As a result, owners and operators of the bulk power transmission system, including Generation, ComEd and PECO, will be subject to mandatory reliability standards promulgated by NERC and enforced by FERC.

In addition, the Energy Policy Act extends the Price-Anderson Act to December 31, 2025. See Note 18—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.

In February 2006, ComEd and PECO received orders from FERC approving their requests for short-term financing authority with FERC in the amounts of $2.5 billion and $1.5 billion, respectively, effective February 8, 2006 through December 31, 2007.

Generation currently has blanket financing authority that it received from FERC with its market-based rate authority in November 2000 and that became effective again with the repeal of PUHCA. As reported previously, the pendency of FERC’s review of Generation’s market-based rate authority

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

established the possibility that the 2000 blanket financing authority could have been revoked retrospectively. See “Market-Based Rates Matters” above for further information. Consequently, Generation continued its reliance on its SEC financing authority that was available under the grandfathering provision of PUHCA 2005. The FERC proceeding was terminated on April 3, 2006, thereby removing any uncertainty over Generation’s market-based rate and blanket financing authority, and Generation subsequently informed FERC that Generation is continuing its reliance for financing authority on the 2000 blanket financing authority. Accordingly, Generation is no longer availing itself of the SEC financing authority under the grandfathering provision of PUHCA 2005 and is no longer subject to the conditions thereunder.

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 FERC.

License Renewals (Exelon and Generation). 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 on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet. The NRC has already approved 20-year renewals of the operating licenses for Generation’s Peach Bottom, Dresden and Quad Cities generating stations. The licenses for Peach Bottom Unit 2, Peach Bottom Unit 3, Dresden Unit 2, Dresden Unit 3, Quad Cities Unit 1 and Quad Cities Unit 2 were renewed to 2033, 2034, 2029, 2031, 2032 and 2032, 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 Operations.

5. Accounts Receivable (Exelon, Generation, ComEd and PECO)

Customer accounts receivable at December 31, 2006 and 2005 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:

2006	Exelon		Generation		ComEd		PECO
Unbilled revenues	$	1,077	$	538	$	296	$	243
Allowance for uncollectible accounts		91		17		20		51

2005	Exelon		Generation		ComEd		PECO
Unbilled revenues	$	1,020	$	524	$	321	$	175
Allowance for uncollectible accounts		77		15		20		39

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. At December 31, 2006, PECO had sold a $225 million interest in accounts receivable, consisting of a $208 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

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Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

No. 140) and a $17 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable (see Note 11—Debt and Credit Agreements). 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 and a $30 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. 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, 2006 and 2005, PECO met this requirement and was not required to make any cash deposits.

Beginning in 2007, this agreement will be subject to the provisions of SFAS No. 156, “Accounting for Servicing of Financial Assets, amendment of FASB Statement No. 140,” which is not expected to have a material impact to PECO.

6. Property, Plant and Equipment (Exelon, Generation, ComEd and PECO)

The following tables present a summary of property, plant and equipment by asset category as of December 31, 2006 and 2005:

December 31, 2006	Exelon		Generation		ComEd		PECO
Asset Category
Electric—transmission and distribution	$	16,385	$	—	$	11,632	$	4,753
Electric—generation		8,154		8,154		—		—
Gas—transmission and distribution		1,537		—		—		1,537
Common		499		—		—		499
Nuclear fuel		2,205		2,205		—		—
Construction work in progress		861		509		256		77
Other property, plant and equipment (a)		384		60		14		13
Total property, plant and equipment		30,025		10,928		11,902		6,879
Less accumulated depreciation (b)		7,250		3,414		1,445		2,228
Property, plant and equipment, net	$	22,775	$	7,514	$	10,457	$	4,651

(a) For Exelon, also includes corporate operations, shared service entities, including Exelon Business Services Company (BSC), Enterprises and investments in synthetic fuel-producing facilities. For Generation, includes buildings under capital lease with a net carrying value of $37 million at December 31, 2006. The original cost basis of the buildings was $53 million and total accumulated amortization was $16 million at December 31, 2006. For ComEd and PECO, represents non-utility property.

(b) For Generation, includes accumulated amortization of nuclear fuel of $1,078 million at December 31, 2006.

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Commonwealth Edison Company and Subsidiary Companies

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Combined Notes to Consolidated Financial Statements—(Continued)

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

December 31, 2005	Exelon		Generation		ComEd		PECO
Asset Category
Electric—transmission and distribution	$	15,463	$	—	$	10,882	$	4,581
Electric—generation		8,083		8,083		—		—
Gas—transmission and distribution		1,483		—		—		1,483
Common		476		—		—		476
Nuclear fuel		3,148		3,148		—		—
Construction work in progress		840		494		253		88
Other property, plant and equipment (a)		360		54		24		15
Total property, plant and equipment		29,853		11,779		11,159		6,643
Less accumulated depreciation (b)		7,872		4,315		1,253		2,172
Property, plant and equipment, net	$	21,981	$	7,464	$	9,906	$	4,471

(a) For Exelon, also includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities. For Generation, includes buildings under capital lease with a net carrying value of $40 million at December 31, 2005. The original cost basis of the buildings was $53 million and total accumulated amortization was $13 million at December 31, 2005. For ComEd and PECO, represents non-utility property.

(b) For Generation, includes accumulated amortization of nuclear fuel of $2,103 million at December 31, 2005.

As of December 31, 2006 and 2005, Exelon had recorded the following accumulated depreciation for regulated and unregulated property, plant and equipment:

	December 31, 2006					December 31, 2005
	Regulated		Unregulated			Regulated		Unregulated
Accumulated depreciation	$	3,673	$	3,577	(a)	$	3,425	$	4,447	(a)

(a) Includes accumulated amortization of nuclear fuel in the reactor core of $1,078 million and $2,103 million as of December 31, 2006 and 2005, respectively.

License Renewals. Generation’s 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 Operations. See Note 4—Regulatory Issues for further information on license renewals.

Depreciation Rate Study. In August 2005, PECO filed a depreciation rate study with the PAPUC for both its electric and gas assets, which resulted in the implementation of new depreciation rates effective March 2006. The impact of the new rates was not material.

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

7. Jointly Owned Electric Utility Plant (Exelon, Generation and PECO)

Exelon’s, Generation’s and PECO’s undivided ownership interests in jointly owned electric plant at December 31, 2006 and 2005 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, 2006:
Plant	$	431		$	461		$	189		$	182		$	218		$	2		$	62
Accumulated depreciation		70			246			60			111			143			1			29
Construction work in progress		34			21			123			13			2			—			—
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			—			—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2006 and 2005.

(b) PECO has a 22.00% ownership interest in 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership interest in 131 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, 2006 and 2005.

Exelon’s, Generation’s and PECO’s undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s and PECO’s share of direct expenses of the jointly owned plants are included in the corresponding operating expenses on Exelon’s, Generation’s and PECO’s Consolidated Statements of Operations.

8. Intangible Assets

Goodwill (Exelon and ComEd)

Pursuant to SFAS No. 142, goodwill is not amortized, but 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

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Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

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

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 assesses goodwill impairment at its ComEd operating segment; 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. In the assessment to estimate the fair value of ComEd, Exelon and ComEd 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. Additionally, ComEd’s estimate of its fair value was compared to a fair value estimate determined by a third-party valuation firm. 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.

The changes in the carrying amount of goodwill for the years ended December 31, 2006 and 2005 were as follows:

Balance as of January 1, 2005	$	4,705
Resolution of certain tax matters		(23	)
Impairment		(1,207	)
Balance as of January 1, 2006		3,475
Resolution of certain tax matters		(5	)
Impairment		(776	)
Balance as of December 31, 2006	$	2,694

2006 Interim Goodwill Impairment Assessment. Exelon and ComEd perform the annual goodwill impairment assessment in the fourth quarter of each year. However, due to the significant negative impact of the ICC’s July 2006 order in ComEd’s Rate Case to the cash flows and value of ComEd, an interim impairment assessment was completed during the third quarter of 2006. Based on the results of ComEd’s interim goodwill impairment analysis, which was determined using the same model and assumptions discussed above, Exelon and ComEd recorded an impairment charge of $776 million associated with the write-off of the goodwill during the third quarter of 2006. See Note 4—Regulatory Issues for further information regarding the Rate Case and the Procurement Case.

2006 Annual Goodwill Impairment Assessment. The annual goodwill impairment assessment was performed as of November 1, 2006. The first step of the annual impairment analysis, comparing the fair value of ComEd to its carrying value, including goodwill, indicated no additional impairment of goodwill.

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

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

value of ComEd 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.

Other Intangible Assets (Exelon)

Exelon’s other intangible assets, included in deferred debits and other assets, consisted of the following as of December 31, 2005:

	Gross		Accumulated Amortization			Net
Synthetic fuel investments (a)	$	264	$	(121	)	$	143
Intangible pension asset (b)		34		—			34
Total intangible assets	$	298	$	(121	)	$	177

(a) See Note 12—Income Taxes for a description of Exelon’s right to acquire tax credits through investments in synthetic fuel-producing facilities. In the second quarter of 2006, Exelon recorded an impairment charge of $115 million (before income taxes) associated with the full write-off of the intangible asset related to its investment in synthetic fuel-producing facilities.

(b) See Note 14—Retirement Benefits for a description of the impact to Exelon’s Consolidated Balance Sheet as a result of adopting SFAS No. 158, including the elimination of the intangible pension asset in 2006.

For the year ended December 31, 2006, Exelon’s amortization expense related to intangible assets was $28 million. For the year ended December 31, 2005, the intangible pension asset decreased by $137 million as a result of an annual actuarial valuation associated with Exelon’s pension plans. 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.

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 2—Acquisitions and Dispositions for further information regarding this sale.

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

9. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd and PECO)

Derivative Financial Assets and Liabilities

Interest-Rate Swaps (Exelon, Generation, ComEd and PECO)

The fair values of the Registrants’ interest-rate swaps are determined using quoted exchange prices, external dealer prices and available market pricing curves. At December 31, 2005, Exelon had $240 million of notional amounts of interest-rate swaps outstanding, which were held by ComEd and were settled on January 17, 2006 for a cash payment of approximately $1 million. At December 31, 2006, the Registrants did not have any cash-flow hedges outstanding.

Fair-Value Hedges. The Registrants may utilize fixed-to-floating interest-rate swaps from time to time as a means to achieve their targeted level of variable-rate debt as a percent of total debt. At December 31, 2006 and 2005, Exelon had $50 million and $240 million, respectively, of notional amounts of fair-value hedges outstanding. At December 31, 2005, ComEd had $240 million of notional amounts of fair-value hedges outstanding. Fixed-to-floating interest-rate swaps are designated as fair-value hedges, as defined in 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 liability remains outstanding, 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 2006 and 2005, no amounts relating to fair-value hedges were recorded in earnings as a result of ineffectiveness.

At December 31, 2006, the fair value associated with interest-rate swaps were as follows:

	Notional Amount		Exelon Pays		Counterparty Pays		Fair Value 12/31/06			Fair Value 12/31/05
Fair-Value Hedges
Exelon	$	50	3 Month LIBOR-.1419	%	4.90	%	$	(0.4	)	$	—

Cash-Flow Hedges. The Registrants may utilize 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, 2006 and 2005, the Registrants 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 ComEd 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 and ComEd’s Consolidated Statements of Operations. Exelon is recording the remaining $39 million as additional interest expense over the remaining life of the related debt.

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Energy-Related Derivatives (Exelon, Generation and ComEd)

Generation utilizes derivatives to manage the utilization of its available generating capacity and the provision of wholesale energy to its affiliates. Exelon and Generation also utilize 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 or are designated as fair-value hedges, in which case those changes are recognized in current earnings offset by changes in the fair value of the hedged item in current earnings. 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 18—Commitments and Contingencies.

ComEd has derivatives related to one wholesale contract and certain other contracts to manage the market price exposures to several wholesale contracts that extend into 2007, which is beyond the expiration of ComEd’s PPA with Generation. ComEd’s wholesale contract, which previously qualified for the normal sale exception pursuant to SFAS No. 133, has been recorded at fair value beginning in the first quarter of 2006 since the exception is no longer applicable. Additionally, the supplier forward contracts that ComEd has entered into as part of the initial ComEd procurement auction (See Note 4—Regulatory Issues) are deemed to be derivatives that qualify for the normal purchase exception to SFAS No. 133. ComEd does not enter into derivatives for speculative or trading purposes.

PECO’s PPA with Generation and its gas supply agreements are deemed to be derivatives that qualify for the normal purchase exception to SFAS No. 133. PECO does not enter into derivatives for speculative or trading purposes.

228

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2006, Exelon, Generation and ComEd had net assets (liabilities) of $496 million, $499 million and $(11) million, respectively, on their Consolidated Balance Sheets for the fair value of energy derivatives. The following table provides a summary of the fair value balances recorded by Exelon, Generation and ComEd as of December 31, 2006:

December 31, 2006	Generation												ComEd												Exelon
																									Energy-
Derivatives	Cash-Flow Hedges			Other Derivatives			Proprietary Trading			Subtotal			Cash-Flow Hedge			Other Derivatives			Subtotal			Other (a)			Related Derivatives (b)
Current assets	$	460		$	751		$	197		$	1,408		$	—		$	—		$	—		$	10		$	1,418
Noncurrent assets		104			52			15			171			—			—			—			—			171
Total mark-to-market energy contract assets	$	564		$	803		$	212		$	1,579		$	—		$	—		$	—		$	10		$	1,589
Current liabilities	$	(119	)	$	(697	)	$	(187	)	$	(1,003	)	$	(6	)	$	(5	)	$	(11	)	$	(1	)	$	(1,015	)
Noncurrent liabilities		(30	)		(33	)		(14	)		(77	)		—			—			—			(1	)		(78	)
Total mark-to-market energy contract liabilities	$	(149	)	$	(730	)	$	(201	)	$	(1,080	)	$	(6	)	$	(5	)	$	(11	)	$	(2	)	$	(1,093	)
Total mark-to-market energy contract net assets (liabilities)	$	415		$	73		$	11		$	499		$	(6	)	$	(5	)	$	(11	)	$	8		$	496

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

(b) Excludes Exelon’s interest-rate swaps.

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2005, Exelon and Generation had net liabilities of $517 million and $540 million, respectively on their 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 and Generation as of December 31, 2005:

December 31, 2005	Generation												Other (a)			Exelon
Derivatives	Cash-Flow Hedges			Other Derivatives			Proprietary Trading			Subtotal						Energy-Related Derivatives (b)
Current assets	$	563		$	327		$	26		$	916		$	—		$	916
Noncurrent assets		153			9			124			286			85			371
Total mark-to-market energy contract assets	$	716		$	336		$	150		$	1,202		$	85		$	1,287
Current liabilities	$	(948	)	$	(316	)	$	(18	)	$	(1,282	)	$	—		$	(1,282	)
Noncurrent liabilities		(289	)		(48	)		(123	)		(460	)		(62	)		(522	)
Total mark-to-market energy contract liabilities	$	(1,237	)	$	(364	)	$	(141	)	$	(1,742	)	$	(62	)	$	(1,804	)
Total mark-to-market energy contract net assets (liabilities)	$	(521	)	$	(28	)	$	9		$	(540	)	$	23		$	(517	)

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

(b) Excludes Exelon’s interest-rate swaps.

Normal Operations and Hedging Activities (Generation). 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 (Generation and ComEd). The tables below provide details of effective cash-flow hedges under SFAS No. 133 included on Exelon’s, Generation’s and ComEd’s Consolidated Balance Sheets as of December 31, 2006. The data in the tables is indicative of the magnitude of SFAS No. 133 hedges Generation and ComEd have in place; however, since under SFAS No. 133 not all derivatives are recorded in OCI, the tables do not provide an all-encompassing picture of Generation’s and ComEd’s derivatives. The tables also include a rollforward of accumulated OCI related to cash-flow hedges for the years ended December 31, 2006 and 2005, providing information about the changes in the fair value of hedges and the reclassification from OCI into earnings.

	Total Cash-Flow Hedge OCI Activity, Net of Income Tax
December 31, 2006	Generation			ComEd			Exelon
Accumulated OCI derivative loss at January 1, 2006	$	(314	)	$	—		$	(314	)
Changes in fair value		476			(4	)		472
Reclassifications from OCI to net income		88			—			88
Accumulated OCI derivative gain (loss) at December 31, 2006	$	250		$	(4	)	$	246

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

December 31, 2005	Total Cash- Flow Hedge OCI Activity, Net of Income Tax
	Exelon and Generation
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	)

At December 31, 2006, Generation and ComEd had net unrealized pre-tax gains (losses) of $415 million and $(6) million, respectively, of cash-flow hedges recorded in accumulated OCI. Based on market prices at December 31, 2006, approximately $341 million and $(6) million of these deferred net pre-tax unrealized gains (losses) on derivative instruments in accumulated OCI are expected to be reclassified to earnings during the next twelve months by Generation and ComEd, respectively. 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 two years. ComEd’s cash flow hedge expires on May 31, 2007.

Generation’s cash-flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $146 million pre-tax loss, a $583 million pre-tax loss and a $475 million pre-tax loss for the years ended December 31, 2006, 2005 and 2004, respectively.

Other Derivatives (Exelon, Generation and ComEd)

Exelon, Generation and ComEd enter 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 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 2006, 2005 and 2004, Exelon, Generation and ComEd recognized the following net unrealized mark-to-market gains (losses), realized mark-to-market gains (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. Generation’s, ComEd’s and Exelon’s other mark-to-market activity on non-trading purchase power and sale contracts are reported in fuel and purchased power, revenue and operating and maintenance expense, respectively.

For the Year Ended December 31, 2006	Generation		ComEd (a)			Other (b)			Exelon
Unrealized mark-to-market gains (losses)	$	29	$	(8	)	$	(15	)	$	6
Realized mark-to-market gains		74		3			—			77
Total net mark-to-market gains (losses)	$	103	$	(5	)	$	(15	)	$	83

(a) See “Energy-Related Derivatives” above.

(b) Other includes corporate operations, shared services entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

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Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2005	Generation			Other (a)		Exelon
Unrealized mark-to-market gains	$	86		$	24	$	110
Realized mark-to-market losses		(98	)		—		(98	)
Total net mark-to-market gains (losses)	$	(12	)	$	24	$	12

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

For the Year Ended December 31, 2004	Exelon and Generation
Unrealized mark-to-market gains	$	181
Realized mark-to-market losses		(183	)
Total net mark-to-market losses	$	(2	)

Proprietary Trading Activities (Generation). 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 Exelon’s Risk Management Committee. These contracts are recognized on the Consolidated Balance Sheets at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. The proprietary trading activities, which included trading volumes of 31,692 GWhs, 26,924 GWhs and 24,001 GWhs for 2006, 2005 and 2004, respectively, are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall energy marketing activities. For 2006, 2005 and 2004, Exelon and Generation recognized the following net unrealized mark-to-market gains, realized mark-to-market (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 and Generation’s Consolidated Statements of Operations.

	For the Year Ended December 31,
	2006			2005			2004
Unrealized mark-to-market gains	$	14		$	18		$	3
Realized mark-to-market losses		(10	)		(3	)		(3	)
Total net mark-to-market gains	$	4		$	15		$	—

Credit Risk Associated with Derivative Instruments. The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into 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 attempts to enter into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to payment netting language in the

232

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

enabling agreement, the credit department establishes credit limits and letter of credit requirements for each counterparty, which are defined in the derivatives contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s credit limit and letter of credit thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

Under the Illinois auction rules and the supplier forward contracts that Generation entered into with ComEd and Ameren, beginning in 2007, collateral postings will be one-sided from Generation only. That is, if market prices fall below ComEd’s or Ameren’s contracted price levels, ComEd or Ameren are not required to post collateral; however, if market prices rise above contracted price levels with ComEd or Ameren, Generation may be required to post collateral.

The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of the Registrants’ 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. Exelon’s and Generation’s credit exposure, net of collateral, as of December 31, 2006 and 2005 were $791 million and $547 million, respectively.

Non-Derivative Financial Assets and Liabilities

Fair Value. As of December 31, 2006 and 2005, the Registrants’ 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.

Exelon

The carrying amounts and fair values of Exelon’s financial liabilities as of December 31, 2006 and 2005 were as follows:

	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	9,144	$	9,122	$	8,166	$	8,231
Long-term debt to ComEd Transitional Funding Trust and PETT (including amounts due within one year)		3,051		3,149		3,963		4,132
Long-term debt to other financing trusts		545		517		545		539
Preferred securities of subsidiaries		87		73		87		70

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation

The carrying amounts and fair values of Generation’s financial liabilities as of December 31, 2006 and 2005 were as follows:

	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	1,790	$	1,821	$	1,800	$	1,856

ComEd

The carrying amounts and fair values of ComEd’s financial liabilities as of December 31, 2006 and 2005 were as follows:

	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	3,579	$	3,592	$	2,828	$	2,887
Long-term debt to ComEd
Transitional Funding Trust (including amounts due within one year)		648		652		987		1,003
Long-term debt to other financing trusts		361		338		361		353

PECO

The carrying amounts and fair values of PECO’s financial liabilities as of December 31, 2006 and 2005 were as follows:

	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	1,469	$	1,464	$	1,183	$	1,180
Long-term debt to PETT (including amounts due within one year)		2,404		2,496		2,975		3,129
Long-term debt to other financing trusts		184		179		184		186

Credit Risk. Financial instruments that potentially subject the Registrants to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. The Registrants place their 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 the Registrants’ large number of customers and, in the case of ComEd’s and PECO’s energy delivery businesses, their dispersion across many industries.

234

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation)

Investments as of December 31, 2006 and 2005. Exelon and Generation classify investments in trust accounts for decommissioning nuclear plants as available-for-sale and estimate their fair value based on quoted market prices for the securities held in decommissioning 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. See Note 13—Asset Retirement Obligations 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, 2006 and 2005:

	December 31, 2006
	Amortized Cost		Unrealized Gains		Unrealized Losses		Estimated Fair Value
Cash and cash equivalents	$	36	$	—	$	—	$	36
U.S. Treasury obligations and direct obligations of U.S. government agencies		990		36		—		1,026
Federal agency mortgage-backed securities		767		6		—		773
Commercial mortgage-backed securities		82		1		—		83
Corporate bonds		306		7		—		313
Other debt securities		137		—		—		137
Marketable equity securities		2,810		1,237		—		4,047
Total available-for-sale securities	$	5,128	$	1,287	$	—	$	6,415

	December 31, 2005
	Amortized Cost		Unrealized Gains		Unrealized Losses			Estimated Fair Value
Cash and cash equivalents	$	80	$	—	$	—		$	80
U.S. Treasury obligations and direct obligations of U.S. government agencies		958		37		(3	)		992
Federal agency mortgage-backed securities		684		3		(6	)		681
Commercial mortgage-backed securities		53		1		(1	)		53
Corporate bonds		303		10		(4	)		309
Other debt securities		58		—		(1	)		57
Marketable equity securities		2,762		683		(32	)		3,413
Total available-for-sale securities	$	4,898	$	734	$	(47	)	$	5,585

235

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The available-for-sale debt securities have contractual maturities as follows:

	December 31, 2006 Estimated Fair Value
Debt securities:
Maturities within 1 year	$	10
Maturities after 1 year through 5 years		398
Maturities after 5 years through 10 years		401
Maturities after 10 years		1,523
Total debt securities	$	2,332

Impairment Evaluation in 2006 and 2005. Beginning in 2006, and in connection with the issuance of FSP 115-1, Generation considers all nuclear decommissioning trust fund investments in an unrealized loss position to be other-than-temporarily impaired. As a result of certain NRC restrictions, Generation is unable to demonstrate its ability and intent to hold the nuclear decommissioning trust fund investments through a recovery period and accordingly recognizes any unrealized holding losses immediately.

During the year ended December 31, 2006, Generation recorded impairment charges totaling $29 million, $1 million and $2 million associated with the decommissioning trust funds of the former ComEd units, the former PECO units and the AmerGen units, respectively. During the year ended December 31, 2005, Generation recorded impairment charges totaling $20 million and $2 million associated with the decommissioning trust funds of the former ComEd and the AmerGen units, respectively. Recognition of the impairment charges associated with the former ComEd and former PECO plants had no significant impact on net income for Exelon’s or Generation’s results of operations or financial position. See Note 13 for further discussion on the impacts to the Statements of Operations and the Balance Sheets for the former ComEd and former PECO units.

Prior to 2006, Exelon and Generation evaluated, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as well as their intent and ability to hold the investment to determine whether an investment was considered other-then-temporarily impaired. Exelon and Generation also considered specific adverse conditions related to the financial health of and business outlook for the investee. Once a decline in fair value was determined to be other-than-temporary, an impairment charge was recorded and a new cost basis was established.

Unrealized Gains and Losses. At December 31, 2006, Exelon and Generation had gross unrealized gains of $1,287 million related to the nuclear decommissioning trust fund investments. At December 31, 2005, Exelon and Generation had gross unrealized gains of $734 million and gross unrealized losses of $47 million related to the nuclear decommissioning trust fund investments. Unrealized gains of $1,287 million and net unrealized gains of $687 million were included in regulatory liabilities or accumulated other comprehensive income in Exelon’s Consolidated Balance Sheets and in noncurrent payables to affiliates or accumulated other comprehensive income in Generation’s Consolidated Balance Sheets at December 31, 2006 and 2005, respectively.

236

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

As of December 31, 2006, there were no available-for-sale securities held in nuclear decommissioning trust funds in an unrealized loss position.

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.

	December 31, 2005
	Less than 12 months					12 months or more					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
U.S. Treasury obligations and direct obligations of U.S. government agencies	$	170	$	(3	)	$	24	$	(1	)	$	194	$	(4	)
Federal agency mortgage-backed securities		387		(4	)		28		(1	)		415		(5	)
Commercial mortgage-backed securities		15		—			7		(1	)		22		(1	)
Corporate bonds		119		(3	)		20		(1	)		139		(4	)
Other debt securities		17		—			22		(1	)		39		(1	)
Marketable equity securities		345		(23	)		69		(9	)		414		(32	)
Total	$	1,053	$	(33	)	$	170	$	(14	)	$	1,223	$	(47	)

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, 2006, 2005 and 2004 were as follows:

	For the Years Ended December 31,
	Proceeds from Sales		Gross Realized Gains		Gross Realized Losses
For the year ended December 31, 2006	$	4,793	$	58	$	(60	)
For the year ended December 31, 2005		5,274		130		(81	)
For the year ended December 31, 2004		2,320		115		(43	)

Amounts reclassified from Exelon’s regulatory liabilities or accumulated other comprehensive income to earnings was determined base on either the high-cost or average cost basis, and totaled a net loss of $2 million, a net gain of $49 million and a net gain of $72 million for the years ended December 31, 2006, 2005 and 2004, respectively. Amounts reclassified from Generation’s noncurrent payables to affiliates or accumulated other comprehensive income to earnings was determined base on either the high-cost or average cost basis, and totaled a net loss of $2 million, a net gain of $49 million and a net gain of $72 million for the years ended December 31, 2006, 2005 and 2004, respectively.

237

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The amounts of net unrealized holding gains that were included in Exelon’s regulatory liabilities or accumulated other comprehensive income during the period totaled $567 million, $132 million, and $293 million for the years ended December 31, 2006, 2005 and 2004, respectively. The amounts of net unrealized holding gains that were included in Generation’s noncurrent payables to affiliates or accumulated other comprehensive income during the period totaled $567 million, $132 million, and $293 million for the years ended December 31, 2006, 2005 and 2004, respectively.

10. Severance Accounting (Exelon, Generation, ComEd and PECO)

The Registrants provide 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. The Registrants account for their ongoing severance plans in accordance with SFAS No. 112 and SFAS No. 88 and accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

Following the termination of the proposed Merger, Exelon evaluated its organizational structure and resource needs on a standalone basis (see Note 2—Acquisitions and Dispositions for further information on the Merger termination). As a result of that evaluation, management concluded that certain positions will be eliminated. Therefore, Exelon recorded $29 million of severance charges in 2006.

During 2006, ComEd recorded a regulatory asset associated with previously incurred severance costs that ComEd was granted recovery of in the December 20, 2006 ICC order. See Note 4—Regulatory Issues and Note 18—Commitments and Contingencies.

The following tables present total salary continuance severance costs (benefits), recorded as an operating and maintenance expense, during 2006, 2005 and 2004:

Salary Continuance Severance	Exelon			Generation			ComEd			PECO		Other (a)
Expense recorded—2006	$	21		$	6	(b)	$	—		$	2	$	13	(c)
Expense (income) recorded—2005		(14	)(d) (e)		(4	)(d) (e)		(9	)(d)		1		(2	)(d)
Expense recorded—2004		32			2			10			3		17

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

(b) Does not include $2 million of severance related to stock-based compensation.

(c) Does not include $4 million of severance related to stock-based compensation and $3 million of severance related to SFAS 88.

(d) Represents a reduction in previously recorded severance reserves.

(e) 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).

238

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides a roll forward of the salary continuance severance obligations from January 1, 2005 through December 31, 2006:

Salary Continuance Obligations	Exelon			Generation			ComEd			PECO			Other (a)
Balance at January 1, 2005	$	69		$	16		$	28		$	7		$	18
Severance charges recorded/(reduction in obligation estimate)		(14	)(b)		(4	) (b)		(9	)		1			(2	)
Cash payments		(33	)		(5	)		(11	)		(7	)		(10	)
Balance at January 1, 2006	$	22		$	7		$	8		$	1		$	6
Severance charges recorded		21			6			—			2			13
Cash payments		(9	)		(3	)		(2	)		(1	)		(3	)
Balance at December 31, 2006	$	34		$	10		$	6		$	2		$	16

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

(b) Excludes severance charges of $5 million related to Salem, of which Generation owns 42.59% and which is operated by PSEG Nuclear.

11. Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)

Short-Term Debt

The following tables present the short-term debt activity for Exelon, Generation, ComEd and PECO during 2006, 2005 and 2004:

Exelon

	2006			2005			2004
Average borrowings	$	856		$	935		$	149
Maximum borrowings outstanding		1,459			2,416			622
Average interest rates, computed on a daily basis		5.02	%		3.49	%		1.37	%
Average interest rates, at December 31		5.42	%		4.59	%		2.43	%

Generation

	2006			2005			2004
Average borrowings	$	214		$	26		$	72
Maximum borrowings outstanding		667			317			326
Average interest rates, computed on a daily basis		4.99	%		4.12	%		1.14	%
Average interest rates, at December 31		—			4.67	%		—

239

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd

	2006			2005			2004
Average borrowings	$	213		$	36		$	7
Maximum borrowings outstanding		669			497			180
Average interest rates, computed on a daily basis		5.06	%		4.13	%		2.11	%
Average interest rates, at December 31		5.43	%		4.50	%		—

PECO

	2006			2005			2004
Average borrowings	$	133		$	30		$	23
Maximum borrowings outstanding		442			257			207
Average interest rates, computed on a daily basis		4.97	%		3.44	%		1.08	%
Average interest rates, computed at December 31		5.41	%		4.58	%		—

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. On July 31, 2006, Exelon amended its $300 million term loan agreement to extend the maturity date to the earlier of December 31, 2006 or two business days after the effective date of Exelon’s new credit facilities. On October 30, 2006, Exelon terminated its $300 million term loan agreement.

Credit Agreements

On July 16, 2004, Exelon, Generation, ComEd and PECO entered into a $1 billion unsecured revolving credit facility maturing on July 16, 2009 and a $500 million unsecured revolving credit facility which matured on October 31, 2006.

On February 10 through 16, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $950 million. On September 19, 2006, Generation entered into three separate 364-day revolving credit facilities with aggregate commitments of $1 billion.

On February 22, 2006, ComEd entered into a $1 billion senior secured three-year revolving credit agreement. The credit agreement is secured by First Mortgage Bonds of ComEd in the principal amount of approximately $1 billion. First Mortgage Bonds are a first mortgage lien on ComEd’s utility assets other than expressly excepted property. Additionally, on February 22, 2006, ComEd was

240

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

removed as a party to the July 16, 2004 credit facilities. During 2006, ComEd borrowed and fully repaid $240 million under its credit agreement.

On October 26, 2006, Exelon, Generation and PECO entered into new unsecured credit facilities of $1 billion, $5 billion and $600 million, respectively. The facilities are for a term of five years and are comprised of three separate facilities with separate borrowers designated by Registrant. The new credit facilities replaced the $1 billion and $500 million Exelon syndicated facilities, the $1.95 billion in Generation bilateral credit facilities and Exelon’s $300 million term loan.

The Registrants may use the credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. The obligation of each lender to make any credit extension to a Registrant under its credit facilities is subject to various conditions including, among other things, that no event of default has occurred for the Registrant or would result from such credit extension. A bankruptcy filing by ComEd would constitute an event of default under ComEd’s credit facilities; however, bankruptcy or another event of default by ComEd would not constitute an event of default for Exelon, Generation or PECO.

At December 31, 2006, the Registrants had the following aggregate bank commitments and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

Borrower	Aggregate Bank Commitment (a)		Available Capacity (b)		Outstanding Commercial Paper
Exelon Corporate	$	1,000	$	993	$	150
Generation		5,000		4,920		—
ComEd		1,000		956		60
PECO		600		598		95

(a) Represents the total bank commitments to the borrower under credit agreements to which the borrower is a party.

(b) Available capacity represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offered 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. In the cases of Exelon, PECO and Generation, the maximum LIBOR adder is 65 basis points; and in the case of ComEd, it is 200 basis points.

Each credit agreement requires the affected borrower 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, 2006:

	Exelon	Generation	ComEd	PECO
Credit agreement threshold	2.50 to 1	3.00 to 1	2.25 to 1	2.00 to 1

At December 31, 2006, the Registrants were in compliance with the foregoing thresholds.

241

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The ComEd credit agreement is secured by first mortgage bonds and imposes a restriction on future mortgage bond issuances by ComEd. It requires ComEd to maintain at least $1.75 billion of issuance availability (ignoring any interest coverage test) in the form of “property additions” or “bondable bond retirements” (previously issued, but now retired, bonds), most of which are required to be maintained in the form of “bondable bond retirements.” In general, a dollar of bonds can be issued under ComEd’s Mortgage on the basis of $1.50 of property additions, subject to an interest coverage test, or $1 of bondable bond retirements, which may or may not be subject to an interest coverage test. As of December 31, 2006, ComEd was in compliance with this requirement.

Long-Term Debt

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd and PECO as of December 31, 2006 and 2005:

Exelon

	Rates	Maturity Date	December 31,
			2006			2005
Long-term debt
First Mortgage Bonds (a) (b):
Fixed rates	3.50%-8.375%	2008-2036	$	4,261		$	3,201
Floating rates	3.50%-3.85%	2012-2020		497			497
Notes payable and other (c)	4.45%-8.00%	2007-2035		3,867			3,928
Pollution control notes:
Floating rates	3.52%-3.97%	2016-2034		520			520
Notes payable—accounts receivable agreement	5.28%	2010		17			30
Sinking fund debentures	3.875%-4.75%	2008-2011		8			10
Total long-term debt				9,170			8,186
Unamortized debt discount and premium, net				(25	)		(25	)
Unamortized settled fair-value hedge, net				(1	)		6
Fair-value hedge carrying value adjustment, net				—			(1	)
Long-term debt due within one year				(248	)		(407	)
Long-term debt			$	8,896		$	7,759
Long-term debt to financing trusts (d)
Payable to ComEd Transitional Funding Trust	5.63%-5.74%	2007-2008	$	648		$	988
Payable to PETT	6.13%-7.65%	2007-2010		2,403			2,975
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 financing trusts				3,596			4,508
Long-term debt due to financing trusts due within one year				(581	)		(507	)
Long-term debt to financing trusts			$	3,015		$	4,001

242

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a) ComEd’s utility assets other than expressly excepted property and substantially all of PECO’s assets are 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 $44 and $46 million at December 31, 2006 and 2005, respectively. Lease payments of $2 million, $2 million, $2 million, $2 million, $2 million and $34 million will be made in 2007, 2008, 2009, 2010, 2011 and thereafter, respectively.

(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, 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.

Generation

			December 31,
	Rates	Maturity Date	2006			2005
Long-term debt
Senior unsecured notes	5.35%-6.95%	2011-2014	$	1,200		$	1,200
Pollution control notes, floating rates	3.52%-3.97%	2016-2034		520			520
Notes payable and other (a)	6.33%-7.83%	2007-2020		73			85
Total long-term debt				1,793			1,805
Unamortized debt discount and premium, net				(3	)		(5	)
Long-term debt due within one year				(12	)		(12	)
Long-term debt			$	1,778		$	1,788

(a) Includes Generation’s capital lease obligations of $44 million and $46 million at December 31, 2006 and 2005, respectively. Generation will make lease payments of $2 million, $2 million, $2 million, $2 million, $2 million and $34 million in 2007, 2008, 2009, 2010, 2011 and thereafter, respectively.

243

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd

			December 31,
	Rates	Maturity Date	2006			2005
Long-term debt
First Mortgage Bonds (a) (b):
Fixed rates	3.70%-8.375%	2008-2036	$	2,961		$	2,201
Floating rates	3.60%-3.85%	2013-2020		343			343
Notes payable
Fixed rates	6.95%-7.625%	2007-2018		285			285
Sinking fund debentures	3.875%-4.75%	2008-2011		8			10
Total long-term debt				3,597			2,839
Unamortized debt discount and premium, net				(17	)		(16	)
Unamortized settled fair-value hedge, net				(1	)		6
Fair-value hedge carrying value adjustment, net				—			(1	)
Long-term debt due within one year				(147	)		(328	)
Long-term debt			$	3,432		$	2,500
Long-term debt to financing trusts (c)
Subordinated debentures to ComEd Financing II	8.50%	2027		155			155
Subordinated debentures to ComEd Financing III	6.35%	2033		206			206
Payable to ComEd Transitional Funding Trust	5.63%-5.74%	2007-2008		648			987
Total long-term debt to financing trusts				1,009			1,348
Long-term debt to financing trusts due within one year				(308	)		(307	)
Long-term debt to financing trusts			$	701		$	1,041

(a) ComEd’s utility assets other than expressly excepted property are 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) 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.

244

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO

	Rates	Maturity Date	December 31,
			2006			2005
Long-term debt
First Mortgage Bonds (a) (b):
Fixed rates	3.50%-5.95%	2008-2036	$	1,300		$	1,000
Floating rates	3.50%-3.70%	2012		154			154
Notes payable—accounts receivable agreement	5.28%	2010		17			30
Total long-term debt				1,471			1,184
Unamortized debt discount and premium, net				(2	)		(1	)
Long-term debt			$	1,469		$	1,183
Long-term debt to financing trusts (c)
PETT Series 1999-A	6.13%	2007-2008	$	848		$	1,419
PETT Series 2000-A	7.63%-7.65%	2008-2009		750			750
PETT Series 2001	6.52%	2010		806			806
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 financing trusts				2,588			3,159
Long-term debt to financing trusts due within one year				(273	)		(199	)
Long-term debt to financing trusts			$	2,315		$	2,960

(a) Substantially all of PECO’s assets are 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.

(c) 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.

Long-term debt maturities at Exelon, Generation, ComEd and PECO in the periods 2007 through 2011 and thereafter are as follows:

Year	Exelon		Generation		ComEd		PECO
2007	$	248	$	12	$	147	$	—
2008		898		12		417		450
2009		28		11		17		—
2010		632		2		213		17
2011		1,799		702		347		250
Thereafter		5,565		1,054		2,456		754
Total	$	9,170	$	1,793	$	3,597	$	1,471

245

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Long-term debt to financing trusts maturities at Exelon, ComEd and PECO in the periods 2007 through 2011 and thereafter are as follows:

Year	Exelon		ComEd		PECO
2007	$	581	$	308	$	273
2008		964		340		625
2009		700		—		700
2010		806		—		806
2011		—		—		—
Thereafter		545		361		184
Total	$	3,596	$	1,009	$	2,588

Issuances of Long-Term Debt. The following long-term debt was issued at Exelon, ComEd and PECO during 2006:

Company	Type	Interest Rate	Maturity	Amount(a)
ComEd	First Mortgage Bonds	5.90%	March 15, 2036	$	325
ComEd	First Mortgage Bonds	5.95%	August 15, 2016		300
ComEd	First Mortgage Bonds	5.95%	August 15, 2016		115
ComEd	First Mortgage Bonds	5.40%	December 15, 2011		345
PECO	First Mortgage Bonds	5.95%	October 1, 2036		300

(a) Excludes unamortized bond discounts and premiums.

Debt Retirements and Redemptions. The following debt was retired, through tender, open market purchases, optional redemption or payment at maturity, during 2006:

Company	Type	Interest Rate		Maturity	Amount
Exelon	Notes payable for investments in synthetic fuel-producing facilities	6.00% to 8.00	%	January 2008	$	50
Generation	Note payable	6.33	%	August 8, 2009		10
ComEd	Pollution Control Revenue Bonds	4.40	%	December 1, 2006		199
ComEd	First Mortgage Bonds	8.25	%	October 1, 2006		95
ComEd	First Mortgage Bonds	8.375	%	October 15, 2006		31
ComEd	Sinking fund	3.875%-4.75	%	2008-2011		2
ComEd	ComEd Transitional Funding Trust	5.63	%	June 25, 2007		339
PECO	PETT	6.05	%	March 1, 2007		522
PECO	PETT	6.13	%	September 1, 2008		49
PECO	Notes payable, accounts receivable agreement	5.28	%	November 12, 2010		13
Other						2

See Note 5—Accounts Receivable for information regarding PECO’s accounts receivable agreement.

See Note 9—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps.

See Note 15—Preferred Securities for additional information regarding preferred stock.

246

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

12. Income Taxes (Exelon, Generation, ComEd and PECO)

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

For the Year Ended December 31, 2006	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	935		$	571		$	282		$	356
Deferred		112			157			83			(156	)
Investment tax credit amortization		(13	)		(8	)		(3	)		(2	)
State
Current		200			122			60			44
Deferred		(28	)		24			23			(62	)
Total income tax expense	$	1,206		$	866		$	445		$	180

For the Year Ended December 31, 2005	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	376		$	315		$	112		$	312
Deferred		411			270			187			(53	)
Investment tax credit amortization		(13	)		(8	)		(3	)		(2	)
State
Current		86			69			25			17
Deferred		84			63			42			(27	)
Total income tax expense	$	944		$	709		$	363		$	247
Included in cumulative effect of changes in accounting principles:
Deferred
Federal	$	(22	)	$	(16	)	$	(5	)	$	(2	)
State		(5	)		(3	)		(1	)		—
Total income tax benefit	$	(27	)	$	(19	)	$	(6	)	$	(2	)

For the Year Ended December 31, 2004	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	406		$	230		$	231		$	311
Deferred		260			114			147			(59	)
Investment tax credit amortization		(13	)		(8	)		(3	)		(2	)
State
Current		86			19			73			36
Deferred		(26	)		46			9			(37	)
Total income tax expense	$	713		$	401		$	457		$	249
Included in cumulative effect of changes in accounting principles:
Deferred
Federal	$	12		$	17		$	—		$	—
State		5			5			—			—
Total income tax expense benefit	$	17		$	22		$	—		$	—

247

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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

For the Year Ended December 31, 2006	Exelon (b)(c)		Generation		ComEd (c)		PECO
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	4.0		4.2		16.2		(1.9	)
Nondeductible goodwill impairment charge	9.7		—		81.6		—
Synthetic fuel-producing facilities credit	(3.6	)	—		—		—
Qualified nuclear decommissioning trust fund income	0.5		0.6		—		—
Manufacturer’s deduction	(0.7	)	(0.9	)	—		—
Tax exempt income	(0.4	)	(0.5	)	—		—
Nontaxable postretirement benefits	(0.4	)	(0.2	)	(0.8	)	(0.2	)
Amortization of investment tax credit	(0.4	)	(0.2	)	(0.9	)	(0.4	)
Investment tax credit charge (refund) (a)	(0.1	)	0.4		—		(2.1	)
Research and development credit charge (refund) (a)	(0.1	)	0.4		—		(2.1	)
Amortization of regulatory asset	0.2		—		1.9		—
Plant basis differences	0.3		—		—		0.6
Other	(0.9	)	(0.6	)	0.6		0.1
Effective income tax rate	43.1	%	38.2	%	133.6	%	29.0	%

For the Year Ended December 31, 2005	Exelon (b)(c)		Generation		ComEd (c)		PECO
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	5.8		4.7		(13.6	)	(0.9	)
Nondeductible goodwill impairment charge	22.3		—		(135.0	)	—
Synthetic fuel-producing facilities credit	(12.6	)	—		—		—
Qualified nuclear decommissioning trust fund income	0.8		0.9		—		—
Manufacturer’s deduction	(0.8	)	(0.8	)	—		—
Tax exempt income	(0.6	)	(0.6	)	—		—
Nontaxable postretirement benefits	(0.6	)	(0.3	)	1.0		(0.3	)
Amortization of investment tax credit	(0.5	)	(0.2	)	1.0		(0.3	)
Amortization of regulatory asset	0.3		—		(2.1	)	—
Plant basis differences	—		—		(0.4	)	(1.1	)
Other	0.7		0.3		(1.9	)	(0.2	)
Effective income tax rate	49.8	%	39.0	%	(116.0	)%	32.2	%

248

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2004	Exelon (b)(c)		Generation		ComEd (c)		PECO
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	1.6		4.0		4.8		(0.1	)
Synthetic fuel-producing facilities credit	(8.4	)	—		—		—
Qualified nuclear decommissioning trust fund income	(0.3	)	(0.7	)	—		—
Tax exempt income	(0.4	)	(0.9	)	—		—
Nontaxable postretirement benefits	(0.3	)	(0.3	)	(0.2	)	—
Amortization of investment tax credit	(0.4	)	(0.5	)	(0.3	)	(0.4	)
Low income housing credit	(0.4	)	—		—		—
Amortization of regulatory asset	0.3		—		0.6		—
Plant basis differences	0.4		—		—		0.6
Other	0.6		1.5		0.4		0.3
Effective income tax rate	27.7	%	38.1	%	40.3	%	35.4	%

(a) See Note 18—Commitments and Contingencies for additional information.

(b) 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. Change between 2005 and 2006 reflects a four month plant shutdown and a 38% credit phase-out.

(c) Change in effective income tax rate between 2006 and 2005 and between 2005 and 2004 is primarily due to the goodwill impairment charge of $776 million and $1.2 billion in 2006 and 2005, respectively.

The tax effects of temporary differences, which give rise to significant portions the deferred tax assets and liabilities, as of December 31, 2006 and 2005 are presented below:

For the Year Ended December 31, 2006	Exelon			Generation			ComEd			PECO
Plant basis differences	$	(4,368	)	$	(856	)	$	(1,937	)	$	(1,407	)
Stranded cost recovery		(1,236	)		—			—			(1,237	)
Unrealized gains on derivative financial instruments		(196	)		(199	)		(5	)		(4	)
Deferred pension and postretirement obligations		408			(203	)		(265	)		24
Emission allowances		(23	)		(23	)		—			—
Decommissioning and decontamination obligations		(38	)		(36	)		—			(3	)
Deferred debt refinancing costs		(78	)		—			(65	)		(13	)
Excess of tax value over book value of impaired assets (a)		65			—			—			—
Goodwill		6			—			—			—
Other, net		230			(4	)		31			79
Deferred income tax liabilities (net)	$	(5,230	)	$	(1,321	)	$	(2,241	)	$	(2,561	)
Unamortized investment tax credits		(259	)		(204	)		(40	)		(15	)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(5,489	)	$	(1,525	)	$	(2,281	)	$	(2,576	)

249

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2005	Exelon			Generation			ComEd			PECO
Plant basis differences	$	(4,291	)	$	(861	)	$	(1,891	)	$	(1,361	)
Stranded cost recovery		(1,465	)		—			—			(1,465	)
Unrealized losses (gains) on derivative financial instruments		195			194			—			(6	)
Deferred pension and postretirement obligations		396			(177	)		(281	)		21
Emission allowances		—			(40	)		—			—
Deferred debt refinancing costs		(49	)		—			(34	)		(15	)
Excess of tax value over book value of impaired assets (a)		41			—			—			—
Decommissioning and decontamination obligations		105			105			—			(5	)
Goodwill		6			—			—			—
Other, net		326			151			72			57
Deferred income tax liabilities (net)	$	(4,736	)	$	(628	)	$	(2,134	)	$	(2,774	)
Unamortized investment tax credits		(262	)		(202	)		(43	)		(17	)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(4,998	)	$	(830	)	$	(2,177	)	$	(2,791	)

(a) In 2006, includes write-downs of certain Enterprises investments and the impairment of the intangible asset related to the synthetic fuel-producing facilities and, in 2005, includes the write-downs of certain Enterprises investments.

In accordance with regulatory treatment of certain temporary differences, Exelon, ComEd and PECO have recorded net regulatory assets associated with deferred income taxes, pursuant to SFAS No. 71 and SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109) as presented below:

	For the Year Ended December 31,
	2006 (a)		2005 (a)
ComEd	$	11	$	8
PECO		790		781
Exelon	$	801	$	789

(a) See Note 19—Supplemental Financial Information for further discussion of Exelon, ComEd and PECO’s regulatory assets associated with deferred income taxes.

ComEd and PECO have certain tax returns that are under review at the audit or appeals level of the Internal Revenue Service (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 Exelon, ComEd or PECO.

At December 31, 2006 and 2005, Exelon had recorded valuation allowances of $37 million and $37 million, respectively, and Generation had recorded valuation allowances of approximately $33 million and $34 million, respectively, with respect to deferred taxes associated with separate company state taxes.

250

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

As of December 31, 2006, Exelon and Generation had net capital loss carryforwards for income tax purposes of approximately $96 million, which will expire after 2011. As of December 31, 2006, the Mexican net operating loss carryforwards of Generation’s subsidiaries are $59 million, which will expire beginning in 2011.

Generation, ComEd, and PECO received allocated tax benefits from Exelon under the Tax Sharing Agreement. The allocations as of December 31, 2006 and 2005 are presented below:

	For the Year Ended December 31,
	2006		2005
Generation	$	47	$	16
ComEd		21		27
PECO		30		15

Investments in Synthetic Fuel-Producing Facilities (Exelon)

Exelon, through three separate wholly owned subsidiaries, owns interests in two limited liability companies and one limited partnership that own 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 the tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. On April 11, 2006, the IRS published the 2005 oil Reference Price and it did not exceed the beginning of the phase-out range. Consequently, there was no phase-out of tax credits for calendar year 2005.

The following table (in dollars) provides the estimated phase-out range for 2006 and the annual average New York Mercantile Exchange, Inc. index (NYMEX) prices per barrel based on actual prices for the year ended December 31, 2006.

	Estimated 2006
Beginning of Phase-Out Range (a)	$	60
End of Phase-Out Range (a)		76
Annual Average NYMEX		66

(a) The estimated 2006 phase-out range is based upon the actual 2005 phase-out range. The actual 2005 phase-out range was determined using the inflation adjustment factor published by the IRS in April 2006. The actual 2005 phase-out range was increased by 2% (Exelon’s estimate of inflation) to arrive at the estimated 2006 phase-out range.

Exelon and the operators of the synthetic fuel-producing facilities in which Exelon has interests idled the facilities in May 2006. The decision to suspend synthetic fuel production was primarily driven by the level and volatility of oil prices. In addition, the proposed Federal legislation that would have provided certainty that tax credits would exist for 2006 production was not included in the Tax Increase Prevention and Reconciliation Act of 2005. As a result of the suspension of production at the synthetic fuel-producing facilities and the level of oil prices, during the second quarter of 2006, Exelon recorded an impairment charge of $115 million ($69 million after tax) in operating and maintenance expense in Exelon’s Consolidated Statement of Operations to write off the net carrying value of the intangible

251

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

asset related to Exelon’s investments in synthetic fuel-producing facilities. The net carrying value of the intangible assets associated with the synthetic fuel-producing facilities was $143 million at December 31, 2005. See Note 8—Intangible Assets for additional information. Due to the reduction in oil prices during the third quarter of 2006, the operators resumed production at the synthetic fuel-producing facilities in September 2006 and produced at full capacity through the remainder of 2006.

Exelon is required to pay for tax credits based on the production of the facilities regardless of whether or not a phase-out of the tax credits is anticipated. However, Exelon has the legal right to recover a portion of the payments made to its counterparties related to phased-out tax credits. At December 31, 2006, Exelon had receivables on its Consolidated Balance Sheet from the counterparties totaling $73 million associated with the portion of the payments previously made to the counterparties related to tax credits that are anticipated to be phased out for 2006. As of December 31, 2006, Exelon has estimated the 2006 phase-out to be 38%, which has reduced Exelon’s earned after-tax credits of $164 million to $101 million for the year ended December 31, 2006. The estimated 2006 phase-out range is based upon the actual 2005 phase-out range. The actual 2005 phase-out range was determined using the inflation adjustment factor published by the IRS in April 2006. The actual 2005 phase-out range was increased by 2% (Exelon’s estimate of inflation) to arrive at the estimated 2006 phase-out range.

In 2005, Exelon and Generation entered into certain derivatives in the normal course of trading operations to economically hedge a portion of the exposure to a phase-out of the tax credits. One of the counterparties has security interests in these derivatives. Including the related mark-to-market gains and losses on these derivatives, interests in synthetic fuel-producing facilities reduced Exelon’s net income by $24 million and increased Exelon’s net income by $81 million and $70 million during the years ended December 31, 2006, 2005 and 2004, respectively. Exelon anticipates that it will continue to record income or losses related to the mark-to-market gains or losses on its derivative instruments and changes to the tax credits earned by Exelon during the period of production due to the volatility of oil prices.

Net income or net losses from interests in synthetic fuel-producing facilities are reflected in the Consolidated Statements of Operations within income taxes, operating and maintenance expense, depreciation and amortization expense, interest expense, equity in losses of unconsolidated affiliates and other, net.

There are provisions in the agreements between the parties, such as low production volume, unanimous consents between the parties and defaults by the parties, which would allow or cause an early termination of the partnerships. If none of the parties to the agreements takes action to terminate the partnerships early, the partnerships will terminate in 2008.

The non-recourse notes payable principal balance was $108 million and $158 million at December 31, 2006 and 2005, respectively. The non-recourse notes payable can be relieved either through eventual payments or possibly through extinguishment which may occur subsequent to termination of the partnership pursuant to the agreements between the parties.

252

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

1999 Sale of Fossil Generating Assets (Exelon and ComEd)

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, 2006 and 2005, 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. 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 sale leaseback transaction into which ComEd entered in connection with the fossil plant sale is proper pursuant to applicable law. The Federal tax returns and related tax return disclosures covering the period of the 1999 sale are currently under IRS audit. The IRS has indicated its position that the ComEd sale leaseback transaction is substantially similar to a leasing transaction, a sale-in, lease-out (SILO), the IRS is treating as a “listed transaction” pursuant to guidance it issued in 2005. A listed transaction is one which the IRS considers to be a potentially abusive tax shelter. As a result of the IRS characterization of the lease transaction as a listed transaction, it is likely to vigorously challenge the transaction and has sought to obtain information not normally requested in audits. Exelon disagrees with the IRS’ characterization of its sale leaseback as a SILO and believes its position is correct and will aggressively defend that position upon audit and any subsequent appeals or litigation.

In November 2006, ComEd received from the IRS a notice of proposed adjustment disallowing the deferral of gain associated with its position that proceeds from the fossil plant sales resulted from an “involuntary conversion.” ComEd plans to protest this adjustment following receipt of the final IRS audit report, which is expected in late 2007.

A successful IRS challenge to ComEd’s positions would accelerate future income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of December 31, 2006, Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $960 million. If the deferral were successfully challenged by the IRS, it could negatively impact Exelon’s results of operations by as much as $166 million (after tax) related to interest expense. 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. Final resolution of this matter is not anticipated for several years.

Pennsylvania Tax Law (Exelon and Generation)

On July 12, 2006, the Governor of Pennsylvania approved a law which increases the threshold for the usage of net operating losses for Pennsylvania corporate net income taxes. Under the new law, previously limited Pennsylvania net operating losses will be available to offset future taxable income, primarily at Generation. As a result, Exelon recorded an approximate $10 million tax benefit to income taxes in 2006.

253

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

13. Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

Nuclear Decommissioning and Spent Fuel Storage (Exelon and Generation)

Exelon, Generation and AmerGen have a legal obligation to decommission nuclear power plants following the expiration of their operating licenses. Generation currently recovers costs for decommissioning nuclear generating stations, previously owned by PECO, through regulated rates collected by PECO from PECO customers. Through 2006, Generation recovered costs for decommissioning nuclear generating stations, previously owned by ComEd, through regulated rates collected from ComEd customers. Under a December 2000 ICC order issued to ComEd, amended February 2001 (ICC order), amounts for decommissioning are no longer permitted to be collected from ComEd customers subsequent to 2006. AmerGen trust funds were originally funded through collections from customers prior to the acquisition of the sites. Neither Exelon nor Generation are permitted to collect any amounts from customers for the decommissioning of the AmerGen sites. The amounts recovered from customers are deposited into decommissioning trust funds that have been established as required by law. 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 and Generation believe 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 and Generation’s Consolidated Balance Sheets as of December 31, 2006 and 2005:

December 31, 2006	Exelon			Generation
Property, plant and equipment (asset retirement cost)	$	275		$	275
Nuclear decommissioning trust funds		6,415			6,415
Regulatory liability		(1,911	)		N/A
Asset retirement obligations		(3,533	)		(3,533	)
Long-term payables to affiliates		N/A			(1,911	)
Other comprehensive income, net		(167	)		(167	)

December 31, 2005	Exelon			Generation
Property, plant and equipment (asset retirement cost)	$	685		$	685
Nuclear decommissioning trust funds		5,585			5,585
Regulatory liability		(1,503	)		N/A
Asset retirement obligations		(3,921	)		(3,921	)
Long-term payables to affiliates		N/A			(1,503	)
Other comprehensive income, net		(76	)		(76	)

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

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

254

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

separated its generation and other competitive businesses from its regulated energy delivery business at ComEd and PECO.

AmerGen assumed responsibility for decommissioning the Clinton, Oyster Creek and Three Mile Island (TMI) 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. 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, 2006 and 2005, Exelon and Generation recorded nuclear decommissioning obligations totaling $3.5 billion and $3.9 billion, respectively, which were determined in accordance with SFAS No. 143. See Note 1—Significant Accounting Policies for information regarding the application of SFAS No. 143.

Nuclear Decommissioning Trust Funds and Customer Collections

The trust funds that have been established to satisfy Exelon’s and 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.

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’s or PECO’s customers as appropriate. However, 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 and up to 5% of any additional shortfalls will be borne by Generation as required by the corporate restructuring in 2001. Exelon and Generation expect 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.

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. 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.

255

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Through 2006, ComEd was permitted to recover up to $73 million annually from customers through regulated rates to pay for decommissioning costs. The amounts recovered from customers were remitted to Generation and deposited into the trust accounts to fund the future decommissioning costs. ComEd collected and remitted to Generation a total of $66 million and $68 million, respectively, for the years ended December 31, 2006 and 2005. ComEd is not permitted to collect any amounts after 2006 to pay for decommissioning costs based on the ICC order. Based on the provisions of the ICC order and NRC regulations, Generation is financially responsible for the decommissioning obligations related to the plants formerly owned by ComEd.

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. In both 2006 and 2005, PECO collected and remitted to Generation $33 million. Every five years, the PAPUC reviews the annual amount that PECO is allowed to collect from customers. As part of that review, the PAPUC will decide whether the amount PECO collects from its customers continues to be sufficient to allow for the decommissioning of the former PECO nuclear units. Based on this review, the PAPUC may adjust PECO’s collection upward or downward. Any shortfall of funding resulting from this process would be funded by Generation, as described above.

As of December 31, 2006 and 2005, nuclear decommissioning trust funds totaled $6.4 billion and $5.6 billion, respectively. See Note 9—Fair Value of Financial Assets and Liabilities for more information regarding the nuclear decommissioning trust funds as of December 31, 2006 and 2005.

Accounting Implications of the Agreements with ComEd and PECO

Impact on the Statements of Operations

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 operations 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 maintain a noncurrent affiliate payable related to ComEd’s corresponding regulatory liability, but rather reflect the net impacts of decommissioning activities related to these plants in the statements of operations.

Decommissioning impacts, including the accretion of the decommissioning obligation (which is included in operating and maintenance expense in Generation’s statements of operations) and the income of the trust funds (net of applicable taxes) associated with the former ComEd and former PECO units, are offset within Generation’s statements of operations with an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd and PECO have recorded equal noncurrent affiliate receivables from Generation and corresponding regulatory liabilities. The decommissioning of the AmerGen units are reflected in the statements of operations, as there are no regulatory agreements associated with these units.

256

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 for the trust funds established to fund the decommissioning liabilities of the former PECO units as these unrealized gains are not anticipated to ultimately be included in the statement of operations as a result of the current accounting discussed above. Unrealized gains (after applicable taxes) related to the former ComEd units are also offset within Generation’s statement of other comprehensive income. The gross unrealized gains 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 liabilities can be appropriately calculated and recorded.

The net unrealized gains 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 ARO in the long-term liability section of Generation’s 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 noncurrent 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’s or PECO’s customers as appropriate. ComEd and PECO have recorded corresponding noncurrent affiliate receivables from Generation and corresponding regulatory liabilities to the applicable customers.

At December 31, 2006 and 2005, ComEd recorded a regulatory liability for the amount of decommissioning-related assets in excess of the ARO totaling $1.8 billion and $1.4 billion, respectively. At December 31, 2006 and 2005, PECO recorded a regulatory liability for the amount of decommissioning-related assets in excess of the ARO totaling $151 million and $68 million, respectively.

257

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides a roll forward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2005 to December 31, 2006:

	Exelon			Generation
Asset retirement obligation at January 1, 2005 (a)	$	3,981		$	3,980
Net decrease resulting from updates to estimated future cash flows		(281	)		(281	)
Accretion expense		243			243
Liability reclassified and disposed (b)		(8	)		(7	)
Payments to decommission retired plants		(14	)		(14	)
Asset retirement obligation at December 31, 2005 (a)		3,921			3,921
Net decrease resulting from updates to estimated future cash flows		(604	)		(604	)
Accretion expense		230			230
Payments to decommission retired plants		(14	)		(14	)
Asset retirement obligation at December 31, 2006	$	3,533		$	3,533

(a) Includes amounts not related to nuclear decommissioning.

(b) Represents the reclassification of $(5) million and $(4) million for Exelon and Generation, respectively, 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.

2006 and 2005 ARO Updates

During the second quarter of 2006, Generation recorded a net decrease in the ARO of approximately $604 million and pre-tax income of $149 million resulting from revisions to estimated future nuclear decommissioning cash flows, primarily due to the following:

• Revised management assumptions concerning an increased likelihood of successful nuclear license renewal efforts due to an increasingly favorable environment for nuclear power and, therefore, an increased likelihood of operating the nuclear plants through a full license extension period; and

• A change in management’s expectation of when the U.S. Department of Energy (DOE) will establish a repository for and begin accepting spent nuclear fuel.

The impact of the above items was to effectively push the estimated future nuclear decommissioning cash flows further into the future and, therefore, reduce the present value of the ARO. This decrease in the ARO resulted in the following corresponding impacts:

• A decrease in Generation’s ARC, which is included in property, plant and equipment in Exelon’s and Generation’s Consolidated Balance Sheets, of approximately $393 million;

• An increase in Generation’s noncurrent payable to ComEd and PECO, which is included in noncurrent payable to affiliates in Generation’s Consolidated Balance Sheets, of approximately $62 million;

• An increase in ComEd’s and PECO’s intercompany receivables from Generation, which are included in noncurrent receivables from affiliates in ComEd’s and PECO’s Consolidated

258

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Balance Sheets, of approximately $36 million and $26 million, respectively, offset by equivalent increases in ComEd’s and PECO’s regulatory liabilities (these changes are also reflected in regulatory liabilities in Exelon’s Consolidated Balance Sheet); and

• The recognition of other operating income totaling $149 million (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, representing the reduction in the ARO in excess of the existing ARC balance for the AmerGen units.

The net decrease in the ARO for the former ComEd units, the former PECO units and the AmerGen units was approximately $219 million, $183 million and $202 million, respectively. As of December 31, 2006, the ARO balances for the former ComEd, the former PECO and the AmerGen units totaled approximately $2,172 million, $912 million and $449 million, respectively.

During the second quarter of 2005, Generation recorded a $281 million net decrease to the ARO resulting from revisions to estimated future nuclear decommissioning cash flows. This update also resulted in a corresponding decrease to the ARC of approximately $251 million, included in property, plant and equipment. The balance of the decrease to the ARO related primarily to the retired units, which have no remaining useful life and, likewise, no existing ARC to offset. The decrease related to these retired units totaled approximately $30 million and was recorded as a credit to income. However, since there was no impact to net income for the decommissioning of the former ComEd and PECO units, the $30 million credit to income was equally offset with a charge to operating income and an adjustment to the intercompany payable to ComEd and PECO of approximately $21 million and $9 million, respectively, at Generation, and an adjustment to the regulatory liabilities at Exelon, ComEd and PECO of $30 million, $21 million and $9 million, respectively. Both the credit to income and the offsetting charge to operating income are included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The net decrease to the ARO resulted primarily from a year-over-year decline in the cost escalation factors used to estimate future undiscounted costs, which was partially offset by an increase resulting from updated decommissioning cost studies received for two nuclear stations. Both the updated escalation factors and the updated cost estimates were provided by independent third-party appraisers. Cost studies are generally updated every three to five years in accordance with NRC regulations and industry practice. The net decrease in the ARO for the former ComEd units, the former PECO units and the AmerGen units resulting from revisions to estimated cash flows during 2005 was $207 million, $40 million and $34 million, respectively. As of December 31, 2005, the ARO balances for the former ComEd, the former PECO and the AmerGen units totaled approximately $2,267 million, $1,041 million and $613 million, respectively.

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

259

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 2017. 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. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2006, the unfunded liability for the one-time fee with interest was $950 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, 2006, was 5.108%. 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 outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owners. 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 2004, Generation 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, in the third quarter of 2004, Generation received $80 million ($53 million after considering amounts due to co-owners of certain stations) in gross reimbursements for storage costs through September 30, 2003. During the fourth quarter of 2005, Generation received a cash reimbursement of $58.5 million, ($35 million after considering amounts due to co-owners of certain nuclear stations) for costs incurred between October 1, 2003 to June 30, 2005. The $58.5 million reimbursement included a reimbursement of $14.4 million for costs incurred before August 2000 by First Energy Corporation, the prior owner of Oyster Creek Station. During the fourth quarter of 2006, Generation received a cash reimbursement of $24.4 million, ($19.5 million after considering amounts due to co-owners of certain nuclear stations) for costs incurred between July 1, 2005 and June 30, 2006. As of December 31, 2006, the amount of spent fuel storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $21 million, which is recorded within accounts receivable, other. This amount is comprised of $10 million, which has been recorded as a reduction to operating and maintenance expense, and $9 million, which has been recorded as a reduction to capital expenditures. The remaining $2 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities. In all cases, annual reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel.

260

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Non-Nuclear AROs (Exelon, Generation, ComEd, and PECO)

As of December 31, 2005, the Registrants 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.

The following table presents the activity of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2006 to December 31, 2006:

	Exelon			Generation		ComEd			PECO
Non-nuclear AROs at January 1, 2006	$	236		$	65	$	151		$	20
Accretion (a)		13			4		7			1
Settlements		(2	)		—		(2	)		—
Non-nuclear AROs at December 31, 2006	$	247		$	69	$	156		$	21

(a) For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulations.

Determination of Conditional AROs

The adoption of FIN 47 required the Registrants to update their existing inventories, 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 the Registrant’s past practices, industry practices, management’s intent and the estimated economic lives of the assets. The management of the Registrants concluded that all significant conditional AROs could be reasonably estimated.

The Registrants were required to measure the conditional AROs at fair value using the methodology prescribed by FIN 47. The transition provisions of FIN 47 required the Registrants 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

261

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, $61 million, $150 million, and $20 million were recorded as of December 31, 2005 for Exelon, Generation, ComEd, and PECO, respectively. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have had a material effect on the liabilities recorded 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 the Registrants 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. Exelon and 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, Exelon, Generation, ComEd, and PECO recorded charges of $42 million (net of income taxes of $27 million), $30 million (net of income taxes of $19 million), $9 million (net of income taxes of $6 million), and $3 million (net of income taxes of $2 million), respectively, as cumulative effects 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, ComEd and PECO recorded regulatory assets of $104 million, $91 million and $13 million, respectively, associated with the adoption of FIN 47.

The following table presents the line items within the Registrants’ Consolidated Statements of Operations 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:

	Exelon			Generation			ComEd			PECO
Consolidated statements of operations line item:
Cumulative effect of a change in accounting principle (net of income taxes of $(27), $(19), $(6), $(2) ) (a)	$	(42	)	$	(30	)	$	(9	)	$	(3	)
Consolidated balance sheets line items—increase (decrease):
Property, plant and equipment, net (b)	$	19		$	12		$	5		$	2
Regulatory assets (c)		104			—			91			13
Deferred income taxes (noncurrent liability)		(27	)		(19	)		(6	)		(2	)
Asset retirement obligations (d)		231			61			150			20
Regulatory liabilities (e)		(39	)		—			(39	)		—

262

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a) Represents the difference between the conditional ARO, net ARC and regulatory assets and liabilities recorded upon adoption, net of income taxes.

(b) For Exelon, Generation, ComEd and PECO, represents capitalized ARC of $52 million, $22 million, $25 million and $5 million, respectively, as an increase to the carrying amount of the associated long-lived assets, net of accumulated depreciation of $33 million, $10 million, $20 million and $3 million, respectively, 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.

(e) Represents removal costs within regulatory liabilities 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 and 2004, adjusted as if FIN 47 had been applied effective during the entirety of those years.

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, Generation’s, ComEd’s and PECO’s Consolidated Statements of Operations and Consolidated Balance Sheets, assuming the provisions of SFAS No. 71 continue to apply.

The liabilities recorded related to the conditional AROs of Exelon are being accreted to their full estimated settlement amounts through the estimated ultimate settlement dates. For Generation, this accretion charge is recorded as an operating and maintenance expense within the Consolidated Statements of Operations. For ComEd and PECO, most of this accretion charge is recorded as an increase to their regulatory assets due to the application of SFAS No. 71.

The net ARC of Exelon is being depreciated over the remaining lives of the related long-lived assets. For Generation, this charge is recorded as depreciation and amortization expense within the Consolidated Statements of Operations. For ComEd and PECO, most of this depreciation charge is recorded as an increase to their regulatory assets due to the application of SFAS No. 71.

14. Retirement Benefits (Exelon, Generation, ComEd and PECO)

Defined Benefit Pension and Other Postretirement Benefits—Consolidated Plans

Exelon

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees, except for those employees of Generation’s wholly owned subsidiary, AmerGen, who participate in the separate AmerGen-sponsored defined benefit pension plan and postretirement benefit plan. Substantially all Exelon non-union employees and electing union employees hired on or after January 1, 2001 participate in Exelon-sponsored cash balance pension plans. Substantially all Exelon 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. In 2005, AmerGen offered its employees a choice to remain in their traditional benefit formula or convert to a cash balance formula.

263

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon’s traditional and cash balance pension plans and AmerGen’s cash balance pension plan are intended to be tax-qualified defined benefit plans, and Exelon submitted applications to the IRS for rulings on the tax-qualification of the form of its plans for non-union and electing union employees. On June 1, 2004, the IRS issued a favorable ruling on the union cash balance plan. Exelon has not yet received a ruling with respect to its non-union plan, and AmerGen has not yet submitted an application with respect to its cash balance formula, due to the IRS temporary moratorium on issuing any rulings to plans that were involved in a “conversion” from a traditional to a cash balance formula. In December 2006, the IRS issued a notice announcing that the moratorium on consideration of determination letters for cash balance plans would be lifted in 2007.

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 and AmerGen utilize assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the remaining service period, rate of compensation increases and the anticipated rate of increase in health care costs, in order to measure the plan obligations and costs to be recognized related to these plans. The impact of changes in these factors on pension and other postretirement benefit obligations is generally recognized over the expected remaining service life of the employees rather than immediately recognized in the income statement. Exelon and AmerGen use a December 31 measurement date for their plans.

Funding is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended. The funded status of the pension and other postretirement benefit obligations 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 actual long-term rates of return on plan assets. Changes in these factors could impact the funded status of these obligations. Exelon made discretionary aggregate contributions of approximately $2 billion to its traditional and cash balance pension plans in 2005. The 2005 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—Debt and Credit Agreements.

In accordance with SFAS No. 158, which became effective in the fourth quarter of 2006, Exelon and Generation are required to recognize the overfunded or underfunded status of their defined benefit pension and other postretirement plans as an asset or liability on their balance sheets as of December 31, 2006. The impacts of adopting SFAS No. 158 to Exelon’s and Generation’s Consolidated Balance Sheets is described in more detail below.

In 2006, President Bush signed into law the Pension Protection Act of 2006 (the Act), which will affect the manner in which many companies, including Exelon and Generation, administer their pension plans. This legislation will require companies to, among other things, increase the amount by which they fund their pension plans, pay higher premiums to the Pension Benefit Guaranty Corporation if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants. This legislation will be effective as of January 1, 2008. Exelon and Generation do not anticipate that the Act will have a material effect on their liquidity and capital resources. Absent changes in plan design as a result of the Act, the Act is not expected to

264

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

materially impact Exelon’s and Generation’s results of operations. Exelon and Generation are currently assessing the impact the Act may have on their plan design, if any.

The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:

	Pension Benefits						Other Postretirement Benefits
	2006			2005			2006			2005
Change in benefit obligation:
Net benefit obligation at beginning of year	$	10,247		$	9,775		$	3,297		$	2,988
Service cost		157			144			99			89
Interest cost		562			546			183			175
Plan participants’ contributions		—			—			22			22
Plan amendments		—			5			—			(17	)
Actuarial loss (gain)		7			351			(95	)		239
Curtailments/settlements		3			—			—			—
Special accounting costs		3			—			—			—
Gross benefits paid		(583	)		(574	)		(184	)		(199	)
Federal subsidy on benefits paid		—			—			8			—
Net benefit obligation at end of year	$	10,396		$	10,247		$	3,330		$	3,297
Change in plan assets:
Fair value of plan assets at beginning of year	$	9,060		$	7,014		$	1,341		$	1,246
Actual return on plan assets		1,145			612			168			58
Employer contributions		23			2,008			165			214
Plan participants’ contributions		—			—			22			22
Gross benefits paid		(583	)		(574	)		(184	)		(199	)
Fair value of plan assets at end of year	$	9,645		$	9,060		$	1,512		$	1,341

The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans as of December 31, 2005 for all plans combined. (In accordance with SFAS No. 158, Exelon and Generation recognized the underfunded status of its defined benefit postretirement plans as a liability on their balance sheets as of December 31, 2006.)

	Pension Benefits			Other Postretirement Benefits
Fair value of plan assets at December 31, 2005	$	9,060		$	1,341
Net benefit obligations at December 31, 2005		10,247			3,297
Funded status (plan assets less plan obligations)		(1,187	)		(1,956	)
Amounts not recognized
Net actuarial loss		3,339			1,245
Prior service cost (credit)		159			(370	)
Net transition obligation		—			67
Net amount recognized	$	2,311		$	(1,014	)

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Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined 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 Exelon’s Consolidated Balance Sheets as of December 31, 2005 for all plans combined:

	Pension Benefits			Other Postretirement Benefits
Prepaid benefit cost	$	2,358		$	—
Accrued benefit cost		(47	)		(1,014	)
Additional minimum liability		(2,202	)		—
Intangible asset		34			—
Accumulated other comprehensive loss		2,168			—
Net amount recognized	$	2,311		$	(1,014	)

The following table presents the incremental effects of applying SFAS No. 158, in connection with SFAS No. 71, as well as the change to the additional minimum liability (AML) as a result of an annual actuarial valuation associated with the benefit plans on Exelon’s Consolidated Balance Sheet as of December 31, 2006 for all plans combined:

	Before Application of SFAS No. 158 Without AML Adjustment			AML Adjustment (a)			SFAS No. 158 Adjustments			After Application of SFAS No. 158
Regulatory assets	$	4,428		$	—		$	1,380	(b)	$	5,808
Pension asset		352			1,596			(1,948	)		—
Other deferred debits and other assets		688			92			(126	)(c)		654
Total deferred debits and other assets		15,558			1,688			(694	)		16,552
Other current liabilities		1,076			—			8			1,084
Total current liabilities		5,787			—			8			5,795
Pension obligations		297			(124	)		574			747
Non-pension postretirement benefit obligations		1,039			—			778			1,817
Deferred income taxes and unamortized investment tax credits		5,523			674			(773	)		5,424
Other deferred credits and other liabilities		762			—			20	(d)		782
Total deferred credits and other liabilities		15,404			550			599			16,553
Accumulated other comprehensive loss		(973	)		1,138			(1,302	)(b)		(1,137	)
Total shareholders’ equity		10,137			1,138			(1,302	)		9,973

(a) The AML was significantly less at December 31, 2006 as compared to December 31, 2005 as Exelon’s most significant pension plan was funded on an accumulated benefit obligation (ABO) basis at December 31, 2006 and thus an AML was not required.

(b) After the adoption of SFAS No. 158 and before applying the provisions of SFAS No. 71, Exelon had an accumulated OCI balance of $2.4 billion attributable to its pension and other postretirement benefit obligations. Exelon subsequently recorded

266

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

a regulatory asset of $1.4 billion and an offsetting reduction on an after-tax basis of AOCI of $866 million representing a reasonable approximation of the actuarial losses, prior service costs and transition obligations of Exelon’s pension and other postretirement benefit plans that are probable of recovery through rates by Exelon’s regulated utilities in future periods.

(c) Represents the write-off of the pension intangible asset as required by SFAS No. 158.

(d) Represents the unfunded obligation related to Exelon’s deferred compensation unit plan.

The following table provides the components of Exelon’s accumulated other comprehensive loss and regulatory assets that have not been recognized as components of periodic benefit cost as of December 31, 2006 for all plans combined:

	Pension Benefits		Other Postretirement Benefits
Transition asset	$	—	$	30
Prior service cost (credit)		139		(149	)
Actuarial loss		1,887		502
Total	$	2,026	$	383

As of December 31, 2006, $15 million and $92 million of the prior service cost and actuarial loss, respectively, related to pension benefits currently in accumulated other comprehensive income will be amortized as components of periodic benefit cost in 2007. As of December 31, 2006, $5 million, $(30) million and $34 million of the transition obligation, prior service gain and actuarial loss, respectively, related to other postretirement benefits currently in accumulated other comprehensive income will be amortized as components of periodic benefit cost in 2007. As of December 31, 2006, $1 million and $56 million of the prior service cost and actuarial loss, respectively, related to pension benefits currently in regulatory assets will be amortized as components of periodic benefit cost in 2007. As of December 31, 2006, $4 million, $(27) million and $33 million of the transition obligation, prior service gain and actuarial loss, respectively, related to other postretirement benefits currently in regulatory assets will be amortized as components of periodic benefit cost in 2007.

The ABO for all defined benefit pension plans was $9,502 million and $9,234 million at December 31, 2006 and 2005, respectively. On an ABO basis, the plans were funded at 102% at December 31, 2006 compared to 98% at December 31, 2005. On a projected benefit obligation (PBO) basis, the plans were funded at 93% at December 31, 2006 compared to 88% at December 31, 2005.

The following table provides the PBO, ABO, and fair value of plan assets for all pension plans with an ABO in excess of plan assets.

	December 31,
	2006		2005
Projected benefit obligation	$	1,241	$	9,457
Accumulated benefit obligation		1,193		8,463
Fair value of plan assets		1,020		8,196

267

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides the PBO, ABO and fair value of all pension plans with a PBO in excess of plan assets.

	December 31,
	2006		2005
Projected benefit obligation	$	10,396	$	9,457
Accumulated benefit obligation		9,502		8,463
Fair value of plan assets		9,645		8,196

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2006, 2005 and 2004 for all plans combined. The table reflects an annualized reduction in 2006, 2005 and 2004 net periodic postretirement benefit cost of approximately $40 million, $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 Exelon’s Consolidated Balance Sheets.

	Pension Benefits									Other Postretirement Benefits
	2006			2005			2004			2006			2005			2004
Service cost	$	157		$	144		$	128		$	99		$	89		$	78
Interest cost		562			546			545			183			175			163
Expected return on assets (a)		(817	)		(767	)		(611	)		(105	)		(98	)		(90	)
Amortization of:
Transition obligation (asset)		—			(4	)		(4	)		9			9			10
Prior service cost (credit)		16			16			15			(91	)		(91	)		(81	)
Actuarial loss		149			121			73			87			81			44
Curtailment/settlement charges		6			—			22			—			—			2
Special accounting costs		3			—			—			—			—			16	(b)
Net periodic benefit cost	$	76		$	56		$	168		$	182		$	165		$	142
Other additional information:
Increase (decrease) in other comprehensive loss (net of tax)	$	1,138		$	10		$	(392	)	$	—		$	—		$	—

(a) The increase in expected return on pension assets during 2006 and 2005 compared to 2004 was primarily attributable to discretionary pension contributions of $2 billion made during the first quarter of 2005.

(b) Represents 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.

In 2004, the additional minimum pension liability was increased by $606 million and Exelon’s shareholders’ equity decreased by $392 million (net of income taxes) as a result of an annual actuarial valuation associated with Exelon’s and AmerGen’s pension plans. In 2005, the additional minimum pension liability was reduced by $150 million and shareholders’ equity increased by $10 million (net of income taxes) primarily as a result of an annual actuarial valuation associated with Exelon’s and

268

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

AmerGen’s pension plans. In 2006, the additional minimum pension liability was reduced by $1.7 billion and shareholders’ equity increased by $1.1 billion primarily as a result of an annual actuarial valuation associated with Exelon’s and AmerGen’s pension plans prior to the recording of SFAS No. 158.

The following weighted average assumptions were used to determine the benefit obligations for all the plans at December 31, 2006, 2005 and 2004:

	Pension Benefits						Other Postretirement Benefits
	2006 (a)		2005		2004		2006 (a)	2005	2004
Discount rate	5.90	%	5.60	%	5.75	%	5.85%	5.60%	5.75%
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%	8.00%	9.00%
							decreasing to ultimate trend of 5.0% in 2012	decreasing to ultimate trend of 5.0% in 2010	decreasing to ultimate trend of 5.0% in 2010

(a) Assumptions used to determine year-end 2006 benefit obligations will be the assumptions used to estimate the expected costs of benefits in 2007.

The following weighted average assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31 2006, 2005 and 2004:

	Pension Benefits						Other Postretirement Benefits
	2006		2005		2004		2006	2005	2004
Discount rate	5.60	%	5.75	%	6.25	%	5.60%	5.75%	6.25%
Expected return on plan assets	9.00	%	9.00	%	9.00	%	8.15%(a)	8.30%(a)	8.33-8.35%(a)
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%	9.00%	10.00%
							decreasing to ultimate trend of 5.0% in 2010	decreasing to ultimate trend of 5.0% in 2010	decreasing to ultimate trend of 4.5% in 2011

(a) Not applicable for the AmerGen-sponsored other postretirement benefits plan.

In managing its pension and postretirement plan assets, Exelon and AmerGen utilize 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 and AmerGen’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

269

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. In the pension trusts, Exelon generally maintains approximately 10% of its plan assets in alternative asset classes. Exelon’s and AmerGen’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 8%.

Exelon’s and AmerGen’s pension plan weighted average asset allocations at December 31, 2006 and 2005 and target allocation for 2006 were as follows:

	Target Allocation at December 31, 2006		Percentage of Plan Assets at December 31,
Asset Category			2006		2005
Equity securities	60-65	%	62	%	61	%
Debt securities	35-40		34		35
Real estate	0-5		4		4
Total			100	%	100	%

Exelon’s other postretirement benefit plan weighted average asset allocations at December 31, 2006 and 2005 and target allocation for 2006 were as follows:

	Target Allocation at December 31, 2006		Percentage of Plan Assets at December 31,
Asset Category			2006		2005
Equity securities	60-65	%	63	%	63	%
Debt securities	35-40		35		35
Real estate	—		2		2
Total			100	%	100	%

Exelon’s and AmerGen’s defined benefit pension plans and postretirement benefit plans do not directly hold shares of Exelon common stock.

270

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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	$	45
on postretirement benefit obligation		418
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components		(37	)
on postretirement benefit obligation		(345	)

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2006 were:

	Pension Benefits		Other Postretirement Benefits (a)
2007	$	567	$	167
2008		569		175
2009		569		182
2010		577		189
2011		590		196
2012 through 2016		3,202		1,071
Total estimated future benefits payments through 2016	$	6,074	$	1,980

(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 2007, 2008, 2009, 2010, 2011 and from 2012 through 2016 are estimated to be $8 million, $9 million, $9 million, $10 million, $11 million and $71 million, respectively.

Exelon, Generation, ComEd and PECO

The prepaid pension asset, pension obligation and non-pension postretirement benefits obligation on Generation’s, ComEd’s and PECO’s Consolidated Balance Sheets reflect their obligations from and to their plan sponsor. Employee-related assets and liabilities, including both pension and SFAS No. 106 postretirement 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 cost to the participating employers based upon several factors, including the measures of active employee participation in each participating unit.

The following approximate amounts were included in capital and operating and maintenance expense, excluding curtailment/settlement costs and special termination benefits costs, during 2006, 2005 and 2004, respectively, for Generation’s, ComEd’s, PECO’s and Exelon Corporate’s allocated portion of the Exelon-sponsored and AmerGen-sponsored pension and postretirement benefit plans:

	Generation (a)		ComEd (a)		PECO (a)		Exelon Corporate (a)(b)
2006	$	114	$	72	$	30	$	33
2005		97		63		30		32
2004		126		86		32		26

(a) The 2006, 2005 and 2004 amounts reflect an annualized reduction in net periodic postretirement benefit cost of $17 million, $15 million and $12 million, respectively, for Generation, $13 million, $13 million and $11 million, respectively, for ComEd, $6 million, $7 million and $7 million, respectively, for PECO, and $4 million, $5 million and $3 million, respectively, for Exelon 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.

(b) Represents amounts billed to Exelon’s subsidiaries through intercompany allocations.

271

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides net contributions made by Generation, ComEd and PECO to the Exelon-sponsored and AmerGen-sponsored pension and other postretirement benefit plans:

	2006		2005		2004
Generation	$	78	$	962	$	220
ComEd		47		865		244
PECO		32		189		14

Exelon expects to contribute $208 million to the benefit plans in 2007, of which Generation, ComEd and PECO expect to contribute $98 million, $50 million and $38 million, 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. Of ComEd’s and PECO’s total 2005 contributions, $803 million and $109 million, respectively, were made in the first quarter and were fully funded by a capital contribution from Exelon.

Pension and Other Postretirement Benefits—AmerGen Plans (Generation)

Investment policies and strategies and key assumptions used to determine benefit obligations and net periodic benefit costs for the AmerGen-sponsored defined benefit pension plans and postretirement benefit plans are the same as those for the Exelon-sponsored plans, as presented above.

The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for the AmerGen-sponsored plans:

	Pension Benefits						Other Postretirement Benefits
	2006			2005			2006			2005
Change in benefit obligation:
Net benefit obligation at beginning of year	$	107		$	90		$	82		$	94
Service cost		12			10			9			8
Interest cost		7			5			5			4
Plan amendments		—			5			—			(17	)
Actuarial (gain)		(1	)		(1	)		(4	)		(6	)
Gross benefits paid		(4	)		(2	)		—			(1	)
Net benefit obligation at end of year	$	121		$	107		$	92		$	82
Change in plan assets:
Fair value of plan assets at beginning of year	$	70		$	53		$	—		$	—
Actual return on plan assets		7			3			—			—
Employer contributions		11			16			—			1
Gross benefits paid		(4	)		(2	)		—			(1	)
Fair value of plan assets at end of year	$	84		$	70		$	—		$	—

272

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2005, Generation’s balance sheet included a liability of $14 million and $99 million related to the pension obligation and other postretirement benefit obligation, respectively. The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans as of December 31, 2005 for the AmerGen-sponsored plans (In accordance with SFAS No. 158, Generation recognized the underfunded status of AmerGen’s defined benefit postretirement plans as a liability on its balance sheet as of December 31, 2006.):

	Pension Benefits			Other Postretirement Benefits
Fair value of plan assets at December 31, 2005	$	70		$	—
Net benefit obligations at December 31, 2005		107			82
Funded status (plan assets less plan obligations)		(37	)		(82	)
Amounts not recognized
Net actuarial loss (gain)		17			(2	)
Prior service cost (credit)		6			(15	)
Net amount recognized	$	(14	)	$	(99	)

The following table presents the incremental effects of applying SFAS No. 158 as well as the change to the AML as a result of an annual actuarial valuation associated with the AmerGen defined benefit pension plans and postretirement benefit plans on Generation’s Consolidated Balance Sheet as of December 31, 2006:

	Before Application of SFAS No. 158 Without AML Adjustment		AML Adjustment		SFAS No. 158 Adjustments			After Application of SFAS No. 158
Other deferred debits and other assets (a)	$	265	$	6	$	(6	)	$	265
Total deferred debits and other assets		7,962		6		(6	)		7,962
Other current liabilities		361		—		1			362
Total current liabilities		2,913		—		1			2,914
Pension obligations		16		6		15			37
Non-pension postretirement benefit obligations		558		—		(20	)		538
Deferred income taxes and unamortized investment tax credits		1,384		—		(1	)		1,383
Total deferred credits and other liabilities		8,736		6		(6	)		8,736
Accumulated other comprehensive loss		414		—		(1	)		413
Total shareholders’ equity		5,481		—		(1	)		5,480

(a) Represents the write-off of the pension intangible asset as required by SFAS No. 158.

273

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides the components of accumulated other comprehensive loss that have not been recognized as components of periodic benefit cost as of December 31, 2006 for the AmerGen-sponsored plans:

	Pension Benefits		Other Postretirement Benefits
Prior service cost (credit)	$	6	$	(13	)
Actuarial loss (gain)		15		(6	)
Total	$	21	$	(19	)

As of December 31, 2006, $1 million of the prior service cost related to pension benefits will be amortized as components of periodic benefit cost in 2007. As of December 31, 2006, $2 million of the prior service credit related to other postretirement benefits will be amortized as components of periodic benefit cost in 2007.

The ABO for the AmerGen-sponsored defined benefit pension plans was $105 million and $95 million at December 31, 2006 and 2005, respectively. On an ABO basis, the plan was funded at 80% at December 31, 2006 compared to 74% at December 31, 2005. On a PBO basis, the plans were funded at 69% at December 31, 2006 compared to 65% at December 31, 2005.

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2006, 2005 and 2004 for the AmerGen-sponsored plans. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

	Pension Benefits									Other Postretirement Benefits
	2006			2005			2004			2006			2005			2004
Service cost	$	11		$	10		$	10		$	9		$	8		$	6
Interest cost		6			5			5			5			4			5
Expected return on assets		(6	)		(7	)		(4	)		—			—			—
Amortization of prior service cost		1			1			—			(2	)		(2	)		—
Net periodic benefit cost	$	12		$	9		$	11		$	12		$	10		$	11

AmerGen’s pension plan weighted average asset allocations at December 31, 2006 and 2005 and target allocation at December 31, 2006 were as follows:

	Target Allocation at December 31, 2006		Percentage of Plan Assets at December 31,
Asset Category			2006		2005
Equity securities	65	%	69	%	67	%
Debt securities	35		31		33
Real estate	—		—		—
Total	100	%	100	%	100	%

274

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Assumed health care cost trend rates have a significant effect on the costs reported for the health care plan. 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	$	3
on postretirement benefit obligation		17
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components		(2	)
on postretirement benefit obligation		(14	)

Estimated future benefit payments to participants in the AmerGen-sponsored pension plan and postretirement benefit plan as of December 31, 2006 were:

	Pension Benefits		Other Postretirement Benefits (a)
2007	$	4	$	1
2008		5		1
2009		5		2
2010		6		2
2011		6		3
2012 through 2016		48		29
Total estimated future benefits payments through 2016	$	74	$	38

(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 the sponsor are not material, with total subsidies to be received through 2016 being under $1 million.

Generation expects to contribute $24 million to the AmerGen benefit plans in 2007.

401(k) Savings Plan (Exelon, Generation, ComEd and PECO)

Exelon, Generation, ComEd and PECO participate 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. Exelon, Generation, ComEd and PECO match a percentage of the employee contribution up to certain limits. The cost of matching contributions to the savings plan totaled the following:

For the Years Ended	Exelon		Generation		ComEd		PECO
2006	$	60	$	30	$	17	$	6
2005		58		28		17		6
2004		57		27		16		6

15. Preferred Securities (Exelon, ComEd and PECO)

At December 31, 2006 and 2005, Exelon was authorized to issue up to 100,000,000 shares of preferred stock, none of which was outstanding.

275

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Preferred and Preference Stock of Subsidiaries

At December 31, 2006 and 2005, 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, 2006 and 2005, 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.

	Redemption Price (a)		December 31,
			2006	2005	2006		2005
			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.

16. Common Stock (Exelon, ComEd and PECO)

At December 31, 2006 and 2005, Exelon’s common stock without par value consisted of 2,000,000,000 shares authorized and 669,863,391 and 666,369,787 shares outstanding, respectively. At December 31, 2006 and 2005, ComEd’s common stock with a $12.50 par value consisted of 250,000,000 shares authorized and 127,016,519 shares outstanding. At December 31, 2006 and 2005, PECO’s common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding.

At December 31, 2006 and 2005, ComEd had 75,486 and 75,720 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, 2006 and 2005, 25,162 and 25,240, respectively, shares of common stock were reserved for the conversion of warrants.

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

Repurchased shares are held as treasury shares and recorded at cost.

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Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. As of December 31, 2006, 12 million shares of common stock have been purchased under the share repurchase program for $615 million. During 2006 and 2005, 3.2 million shares and 6.8 million shares, respectively, of common stock were purchased under the share repurchase program for $186 million and $354 million, respectively.

Other Share Repurchases. During both 2005 and 2004, Exelon repurchased 0.2 million shares of common stock from a retired executive for $8 million and $7 million, respectively.

Undistributed Losses of Equity Method Investments

Exelon, Generation, ComEd and PECO had undistributed losses of equity method investments of $391 million, $16 million, $52 million and $51 million, respectively, at December 31, 2006 and $276 million, $7 million, $38 million and $41 million, respectively, at December 31, 2005. See Note 19—Supplemental Financial Information for further detail on the Registrants’ equity method investments.

Stock-Based Compensation Plans

Exelon maintains LTIPs for certain full-time salaried employees. See Note 1—Significant Accounting Policies—SFAS No. 123-R for further information.

277

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

17. Earnings Per Share (Exelon)

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:

	2006		2005			2004
Income from continuing operations	$	1,590	$	951		$	1,870
Income (loss) from discontinued operations		2		14			(29	)
Income before cumulative effect of changes in accounting principles		1,592		965			1,841
Cumulative effect of changes in accounting principles		—		(42	)		23
Net income	$	1,592	$	923		$	1,864
Average common shares outstanding—basic		670		669			661
Assumed exercise of stock-based awards		6		7			8
Average common shares outstanding—diluted		676		676			669

The number of stock-based awards not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 3 million for 2006. There were no stock options excluded for 2005 and 2004.

18. Commitments and Contingencies (Exelon, Generation, ComEd and PECO)

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, 2006, 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 each nuclear operator 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 United States Congress could impose revenue-raising measures on the nuclear industry to pay claims.

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 Policy Act.

Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning

278

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 $173 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 $46 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would also not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act, as extended, as described above.

In addition, Generation participates in the 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.

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 power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are firm commitments related to

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

power generation of specific generation plants and/or are dispatchable in nature. Generation enters into power purchase 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, 2006, 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 (b)
2007	$	468	$	5,401	$	1,499	$	6
2008		425		1,900		475		—
2009		398		647		194		—
2010		417		100		194		—
2011		417		—		106		—
Thereafter		2,960		—		249		—
Total	$	5,085	$	8,048	$	2,717	$	6

(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, 2006. Expected payments include certain capacity charges which are contingent on plant availability.

(b) Transmission rights purchases include estimated commitments in 2007 for additional transmission rights that will be required to fulfill firm sales contracts.

Starting in 2007, as a result of the first reverse-auction competitive bidding process, ComEd will procure substantially all of its supply under supplier forward contracts with various suppliers. See Note 4—Regulatory Issues for further information.

PECO has a long-term 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.

280

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Fuel Purchase Obligations

In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation and PECO has commitments to purchase natural gas and related transportation and storage capacity and services. As of December 31, 2006, these commitments were as follows:

			Expiration within
	Total		2007		2008-2009		2010-2011		2012 and beyond
Generation	$	4,516	$	830	$	1,317	$	1,104	$	1,265
PECO		506		217		146		65		78

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2006, representing commitments potentially triggered by future events, were as follows:

	Expiration within
	Total		2007		2008-2009		2010-2011		2012 and beyond
Letters of credit (non-debt) (a)	$	171	$	169	$	2	$	—	$	—
Letters of credit (long-term debt)—interest coverage (b)		15		15		—		—		—
Surety bonds (c)		236		96		57		—		83
Performance guarantees (d)		296		—		—		—		296
Energy marketing contract guarantees (e)		223		206		3		—		14
Nuclear insurance premiums (f)		1,710		—		—		—		1,710
Lease guarantees (g)		9		—		—		—		9
Midwest Generation Capacity Reservation Agreement guarantee (h)		22		4		8		8		2
Exelon New England guarantees (i)		14		1		2		2		9
Total commercial commitments	$	2,696	$	491	$	72	$	10	$	2,123

(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, 2006, Exelon had $89 million of outstanding letters of credit (non-debt) issued under its $6.6 billion credit agreements. Guarantees of $17 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 agreements, 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.

281

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

(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, $2 million is included as a liability on Exelon’s Consolidated Balance Sheets at December 31, 2006.

(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 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 $13 million and $1 million are included as a noncurrent liability and current liability, respectively, within the Consolidated Balance Sheets of Exelon as of December 31, 2006 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.

Generation’s commercial commitments as of December 31, 2006, representing commitments potentially triggered by future events, were as follows:

			Expiration within
	Total		2007		2008-2009		2010-2011		2012 and beyond
Letters of credit (non-debt) (a)	$	89	$	87	$	2	$	—	$	—
Letters of credit (long-term debt)—interest coverage (b)		15		15		—		—		—
Surety bonds (c)		2		—		2		—		—
Performance guarantees (d)		296		—		—		—		296
Energy marketing contract guarantees (c)		223		206		4		—		13
Nuclear insurance premiums (f)		1,710		—		—		—		1,710
Exelon New England guarantees (g)		14		1		2		2		9
Other		6		6		—		—		—
Total commercial commitments	$	2,355	$	315	$	10	$	2	$	2,028

(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 $11 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) Surety bonds—Guarantees issued related to contract and commercial agreements, 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) 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 $13 million and $1 million are included as a noncurrent

282

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

liability and current liability, respectively, within the Consolidated Balance Sheets of Generation as of December 31, 2006 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 included in current liabilities total less than $1 million.

ComEd’s commercial commitments as of December 31, 2006, representing commitments potentially triggered by future events, were as follows:

			Expiration within
	Total		2007		2008-2009		2010-2011		2012 and beyond
Letters of credit (non-debt) (a)	$	44	$	44	$	—	$	—	$	—
Midwest Generation Capacity Reservation Agreement guarantee (b)		22		4		8		8		2
Surety bonds (c)		2		2		—		—		—
Other		6		6		—		—		—
Total commercial commitments	$	74	$	56	$	8	$	8	$	2

(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), $2 million is included as a liability on ComEd’s Consolidated Balance Sheets at December 31, 2006.

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

PECO’s commercial commitments as of December 31, 2006, representing commitments potentially triggered by future events, were as follows:

			Expiration within
	Total		2007		2008-2009		2010-2011		2012 and beyond
Letters of credit (non-debt) (a)	$	31	$	31	$	—	$	—	$	—
Surety bonds (b)		25		25		—		—		—
Other		2		2		—		—		—
Total commercial commitments	$	58	$	58	$	—	$	—	$	—

(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 agreements, excluding bid bonds.

283

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars and office equipment, as of December 31, 2006 were:

	Exelon			Generation			ComEd		PECO
2007	$	58		$	33		$	19	$	1
2008		57			32			20		1
2009		53			30			18		1
2010		49			28			15		1
2011		44			25			15		—
Remaining years		455			355			56		1
Total minimum future lease payments	$	716	(a)	$	503	(a)	$	143	$	5

(a) Excludes Generation’s tolling agreements that are accounted for as contingent operating lease payments.

The Registrants’ rental expense under operating leases were as follows:

	Exelon		Generation (a)		ComEd		PECO
2006	$	752	$	727	$	18	$	3
2005		836		798		16		4
2004		709		678		22		4

(a) Includes Generation’s tolling agreements that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generations tolling agreements totaled $698 million, $768 million and $645 million during 2006, 2005 and 2004, respectively.

For information regarding capital lease obligations, see Note 11–Debt and Credit Agreements.

Environmental Issues

General. The Registrants’ 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, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants 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. For almost all of these sites, ComEd or PECO is one of several Potentially Responsible Parties (PRPs) which may be responsible for ultimate remediation of each location. Of these 42 sites identified by ComEd, the Illinois Environmental Protection Agency has approved the clean up of nine sites and of the 27 sites identified by PECO, the Pennsylvania Department of Environmental Protection has approved the cleanup of 12 sites. Of the remaining sites identified by ComEd and PECO, 20 and 10 sites, respectively, are currently under

284

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

some degree of active study and/or remediation. ComEd and PECO anticipate that the majority of the remediation at these sites will continue through at least 2015 and 2012, respectively. In addition, 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.

ComEd and Nicor Gas Company, a subsidiary of Nicor Inc. (Nicor), are parties to an interim agreement under which they cooperate in remediation activities at 38 former MGP sites for which ComEd or Nicor, or both, may have responsibility. Under the interim agreement, costs are split evenly between ComEd and Nicor pending their final agreement on allocation of costs at each site, but either party may demand arbitration if the parties cannot agree on a final allocation of costs. For most of the sites, the interim agreement contemplates that neither party will pay less than 20%, nor more than 80% of the final costs for each site. ComEd’s accrual for these environmental liabilities is based on ComEd’s estimate of its 50% share of costs under the interim agreement with Nicor. On April 17, 2006, Nicor submitted a demand for arbitration of the cost allocation for 38 MGP sites. Through December 31, 2006, ComEd has incurred approximately $116 million associated with remediation of the sites in question. Although ComEd believes that the arbitration proceedings will not result in an allocation of costs materially different from ComEd’s current estimate of its aggregate remediation costs for MGP sites, the outcome of the arbitration proceedings is not certain and could result in a material increase or decrease of ComEd’s estimate of its share of the aggregate remediation costs.

Pursuant to a PAPUC order, PECO is currently recovering a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset. Based on the final order received in ComEd’s Rate Case, beginning in 2007, ComEd will also recover its MGP remediation costs from customers for which it established a regulatory asset (see ComEd Rate Case below). See Note 19—Supplemental Financial Information for further information regarding regulatory assets and liabilities.

As of December 31, 2006 and 2005, the Registrants had accrued the following amounts for environmental liabilities in Other Deferred Credits and Other Liabilities within their Consolidated Balance Sheets:

December 31, 2006	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation (a)
Exelon	$	119	$	88
Generation		20		—
ComEd		58		49
PECO		41		39
December 31, 2005	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation (a)
Exelon	$	128	$	89
Generation		27		—
ComEd		54		48
PECO		47		41

(a) Prior to the third quarter 2006, ComEd and PECO discounted their reserves for MGP investigation and remediation. The change from discounting to undiscounting was not deemed to be material for either ComEd or PECO.

285

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

During the first quarter of 2006, a court-approved settlement was completed between PECO and various PRPs with the remediation of a Superfund site commonly referred to as the Metal Bank or Cottman Avenue site. As a result of this settlement, PECO reversed a $4 million reserve it had previously recorded related to the site.

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, 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 United States Environmental Protection Agency (EPA) issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. The Clean Water Act requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. The Phase II rule established national performance standards for reducing entrainment and impingement of aquatic organisms at existing power plants. The rule provided each facility with a number of compliance options and permits site-specific variances based on a cost-benefit analysis. The requirements were intended to 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, Salem and Schuylkill. Since promulgation of the rule, Generation has been evaluating compliance options at its affected plants and meeting interim compliance deadlines.

On January 25, 2007, the U.S. Second Circuit Court of Appeals issued its opinion in a challenge to the final Phase II rule brought by environmental groups and several states. The court found that with respect to a number of significant provisions of the rule the EPA either exceeded its authority under the Clean Water Act, failed to adequately set forth its rationale for the rule, or failed to follow required procedures for public notice and comment. The court remanded the rule back to the EPA for revisions consistent with the court’s opinion. By its action the court invalidated compliance measures that the utility industry supported because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its location and operations. For example, the court found that environmental restoration does not qualify as a compliance option and site-specific compliance variances based on a cost-benefit analysis are impermissible.

The court’s opinion has created significant uncertainty about the specific nature, scope and timing of the final compliance requirements. It is not yet known whether the EPA, or any of the industry petitioners, will seek a review by the U.S. Supreme Court. The EPA has not issued guidance about the impact on current compliance deadlines, or set a schedule to undertake the revisions to the rule necessitated by the court opinion. Due to this uncertainty, 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. If the final rule has performance standards that require the reduction of cooling water intake flow at the plants consistent with closed loop cooling systems, then the impact on the operation of the facilities and Exelon’s and Generation’s future results of operations, financial position and cash flows could be material.

286

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 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 and must evaluate the final regulations issued by the EPA as a result of the decision of the U.S. Second Circuit Court of Appeals, discussed above. 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, which expired 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. PSEG continues to operate Salem under the approved June 2001, NDPES permit while the NDPES permit renewal application is being reviewed. If application of the final 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 and 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.

Nuclear Generating Station Groundwater. On December 16, 2005 and February 27, 2006, the Illinois EPA issued violation notices to Generation alleging violations of state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station (Braidwood). In November 2005, Generation discovered that spills from the line in 1996, 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels in portions of the plume exceed Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant showed that, with one exception, tritium levels in these wells were at levels that naturally occur. The tritium level in one drinking water well was elevated above levels that occur naturally, but was significantly below the state and Federal drinking water standards, and Generation believes that this level posed no threat to human health. Generation has investigated the causes of the releases and has taken the necessary corrective actions to prevent another occurrence. Generation notified the owners of 14 potentially affected adjacent properties that, upon sale of their property, Generation will reimburse the owners for any diminution in property value caused by the tritium release. As of December 31, 2006, Generation has purchased four of the 14 adjacent properties.

On March 13, 2006, a class action lawsuit was filed against Exelon, Generation and ComEd (as the prior owner of Braidwood) in Federal District Court for the Northern District of Illinois on behalf of all persons who live or own property within 10 miles of Braidwood. The plaintiffs primarily are seeking compensation for diminished property values. On March 14 and 23, 2006, 37 area residents filed two

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Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

separate but identical lawsuits against Exelon, Generation and ComEd in the Circuit Court of Will County, Illinois alleging property contamination and seeking compensation for diminished property values. Exelon removed these cases to Federal court, and all three cases were assigned to the same District Court judge. Subsequently, seven plaintiffs withdrew from the cases, and 18 additional plaintiffs were added. On October 11, 2006, two area residents filed a lawsuit in the U.S. District Court for the Northern District of Illinois against Exelon, Generation and ComEd. The allegations in the complaint are substantially similar to the lawsuits described above, and the case has been transferred to the judge overseeing the other Federal cases. Generation has tendered its defense of these lawsuits to its insurance carrier, ANI, and ANI has agreed to defend the suits subject to a reservation of rights. Exelon, Generation and ComEd continue to believe that these lawsuits are without merit and will continue to vigorously defend them.

On March 16, 2006, the Attorney General of the State of Illinois and the State’s Attorney for Will County, Illinois filed a civil enforcement action against Exelon, Generation and ComEd in the Circuit Court of Will County relating to the releases of tritium discussed above and alleging that, beginning on or before 1996, and with additional events in 1998, 2000 and 2005, there have been tritium and other non-radioactive wastes discharged from Braidwood in violation of Braidwood’s NPDES permit, the Illinois Environmental Protection Act and regulations of the Illinois Pollution Control Board. The lawsuit seeks injunctive relief relating to the discontinuation of the liquid tritium discharge line until further court order, soil and groundwater testing, prevention of future releases and off-site migration and to provide potable drinking water to area residents. The action also seeks the maximum civil penalties allowed by the statute and regulations, $10,000 or $50,000 for each violation (depending on the specific violation), and $10,000 for each day during which a violation continues. On May 24, 2006, the Circuit Court of Will County, Illinois entered an order resulting in Generation commencing remediation efforts in June 2006 for tritium in groundwater off of plant property. Among other things, the May 24, 2006 order requires Generation to conduct certain studies and implement measures to ensure that tritium does not leave plant property at levels in excess of the United States EPA safe drinking water standard. Any civil penalty will not be determined until the consent decree is finalized. Generation is unable to determine the amount of the penalty that will be sought. Furthermore, the Circuit Court of Will County may exercise its discretion in determining the final penalty, if any, taking into account a number of factors, including corrective actions taken by Generation and other mitigating circumstances. Given the allegations in the lawsuit regarding the number of violations alleged and their duration, the civil penalty that could be imposed may be material to Exelon’s and Generation’s financial position, results of operations and cash flows.

As of December 31, 2006 and 2005, Generation recorded a reserve of $3 million and $7 million (pre-tax), respectively, related to the matters described above, which Generation deems adequate to cover the costs of remediation and potential related corrective measures.

As a result of intensified monitoring and inspection efforts in 2006, Generation detected small underground tritium leaks at the Dresden Nuclear Generating Station (Dresden) and at the Byron Nuclear Generating Station (Byron). Neither of these discharges occurred outside the property lines of the plant, nor does Generation believe either of these matters poses health or safety threats to employees or to the public. Generation identified the source of the leaks and implemented repairs. On March 31, 2006 and April 12, 2006, the Illinois EPA issued a violation notice to Generation in

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Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

connection with the Dresden and Byron leaks, respectively, alleging various violations, including those related to (1) Illinois groundwater standards, (2) non-permitted discharges, and (3) each station’s NPDES permit. Generation has analyzed the remediation options related to these matters and submitted its response and proposed remediation plan to the Illinois EPA. On July 10, 2006, the Illinois EPA rejected the remediation plan for Dresden and on July 12, 2006, the Illinois EPA sent a Notice of Intention to Pursue Legal Action. On July 17, 2006, the Illinois EPA rejected the remediation plan for Byron and has referred the matter to the Illinois Attorney General for consideration of formal enforcement action and the imposition of penalties.

Generation is actively discussing the violation notice and Attorney General civil enforcement matters discussed above with the Illinois EPA and the Attorneys General for Illinois and the Counties in which the plants are located. Generation expects these matters to be resolved during 2007.

In response to the detection of tritium in water samples taken at the aforementioned nuclear generating stations, in the first quarter of 2006, Generation launched an initiative across its 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. On September 28, 2006, Generation announced the final results of the assessment, concluding that no active leaks had been identified at any of Generation’s 11 nuclear plants and no detectable tritium had been identified beyond any of the plants’ boundaries other than from permitted discharges, with the exception of Braidwood, as discussed above. The assessment further concluded that none of the tritium concentrations identified in the assessment pose a health or safety threat to the public or to Generation’s employees or contractors. Generation management does not believe the costs of any additional work arising from the assessment would be material to Exelon’s or Generation’s financial position, results of operations or cash flows.

Generation recorded $16 million in operating and maintenance expenses and $11 million in capital expenditures during the year ended December 31, 2006, as compared to recording $8 million in operating and maintenance expenses during the year ended December 31, 2005, related to matters arising from groundwater issues at its Nuclear Stations.

Exelon, Generation or ComEd cannot determine the outcome of the above-described matters but believe their ultimate resolution should not, after consideration of reserves established, have a significant impact on Exelon’s, Generation’s or ComEd’s financial position, results of operations or cash flows.

On December 22, 2006, as a gesture of goodwill and corporate citizenship, Generation contributed $11.5 million into an escrow account to assist the Godley Public Water District with the installation of a new public drinking water system for the Village of Godley.

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

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Commonwealth Edison Company and Subsidiary Companies

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 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 $24 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 8% from 2001 levels by the end of 2008. The 8% 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 United States EPA’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. Exelon believes that its planned GHG 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.

Air Quality Regulation. Pursuant to EPA regulations that will impose limits on certain future emissions by generation stations, the co-owners of the Keystone generating station formally approved on June 30, 2006 a capital plan to install SO₂ scrubbers at the station for which Exelon’s share, based on its 20.99% ownership interest, would be approximately $150 million over the life of the control project.

Litigation and Regulatory Matters

Exelon, Generation and PECO

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 age and race 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 included 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 those positions. Exelon, PECO and Generation filed an answer denying all liability. Additionally, since the initial claim was filed, the plaintiffs’ attorneys have identified two additional PECO employees and three additional Generation employees whom they are representing with similar claims, one of whom filed a separate reverse age and race discrimination lawsuit in the United States District Court for the Eastern District of Pennsylvania on July 28, 2006.

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Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

On June 12, 2006, the five named plaintiffs filed an amended complaint and a motion seeking certification of a class comprising all white male employees of Exelon, its subsidiaries, affiliates and operating units. On behalf of the class, the plaintiffs sought to enjoin certain of Exelon’s diversity efforts that they claim resulted in racially discriminatory hiring, promotion, retention, termination and compensation practices, but no monetary damages. On June 29, 2006, Exelon, PECO and Generation filed an answer to the amended complaint again denying all liability.

On September 14, 2006, the court denied the plaintiffs’ request for class certification. In October 2006, PECO and Generation reached a settlement with all parties to this matter. The amount of the settlement was paid in December 2006 and did not have a material impact on Exelon’s, PECO’s or Generation’s financial condition, results of operations or cash flows.

PJM Billing Dispute. In December 2004, Exelon filed a complaint with FERC against PJM and PPL Electric (PPL) 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’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 took from the Elroy substation and used to serve PPL load.

On September 14, 2005, Exelon and PPL filed a proposed settlement of this matter with FERC. If the settlement was approved by FERC, Exelon would have received a total of $40 million, plus interest, over the next four years from two funding sources: (a) $33 million from PPL and (b) $7 million from PJM market participants. In an order issued March 21, 2006, FERC rejected the proposed settlement and set the matter for hearing, primarily because the proposed settlement would have required PJM market participants to bear $7 million of the $40 million settlement, plus interest. The order found that PPL should pay for energy received that was billed to other parties, but allows PPL and the market participants to question what portion of the settlement PJM might bear and what offsetting deductions might be made in reducing the payment.

On March 30, 2006, Exelon and PPL filed with FERC a second proposed settlement agreement, superceding the first, under which Exelon would receive a total of $40 million, plus interest, over the next five years through credits provided by PJM, which would be funded through a surcharge imposed by PJM through its tariff solely on PPL, with no amount being paid by other PJM participants.

On November 9, 2006, FERC issued an order accepting the second proposed settlement agreement, with modifications related to the characterization of the PJM charge to PPL as a transmission charge. On December 11, 2006, PPL and Exelon made a compliance filing accepting the modifications in FERC’s order and altering both the settlement amount and the timing of payment. In this third settlement agreement, PPL agreed to directly pay Exelon approximately $42 million in a lump sum payment (comprised of $38 million of erroneous charges, plus interest of $4 million), which will not be characterized as a transmission charge. It is anticipated that approximately 75% and 25% of the proposed settlement amount will be received by Generation and PECO, respectively. FERC approval is required for this third settlement agreement to become effective. FERC established a comment period that ended January 11, 2007. FERC will issue an order either accepting, accepting with modifications, or rejecting the third settlement agreement sometime after the expiration of the comment period.

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Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon expects this matter to be favorably resolved during 2007; however, pending FERC approval of the proposed settlement agreement, as well as resolution of any third-party interventions, Exelon, Generation and PECO have not recorded any receivables associated with this matter.

Real Estate Tax Appeals. PECO and Generation each have been challenging real estate taxes assessed on certain 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 Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom). Generation is involved in real estate tax appeals for 2000 through 2004 regarding the valuation of its Peach Bottom plant and is in the process of evaluating appraisals and preparing for negotiations. Generation was also previously involved in an appeal regarding the valuation of its LaSalle Nuclear plant. On March 9, 2006, the Illinois Circuit Court for LaSalle County approved the property tax settlement agreement agreed upon in late 2005 between all taxing bodies with jurisdiction over the plant and Generation. The settlement agreement resolved all pending litigation concerning assessments on the property and sets the assessments for the tax years 2005 through 2008. The ultimate outcome of such matters, however, remains uncertain and could result in unfavorable or favorable impacts to the consolidated financial statements of Exelon, PECO and Generation. PECO and Generation believe their reserve balances for exposures associated with real estate taxes as of December 31, 2006 and 2005 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5.

Exelon and Generation

Asbestos Personal Injury Claims. In the second quarter of 2005, Generation engaged independent actuaries to determine if, based on historical claims data and other available information, a reasonable estimate of future losses could be calculated associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. 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 did not include estimated legal costs associated with handling these matters, which could be material. Generation’s 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. The $43 million pre-tax charge was recorded as part of operating and maintenance expense in Generation’s Consolidated Statements of Operations and Comprehensive Income in 2005 and reduced net income by $27 million after tax. During 2006, Generation performed a periodic update to this reserve, which did not result in a material adjustment.

At December 31, 2006 and 2005, Generation had reserved approximately $48 million in total for asbestos-related bodily injury claims. As of December 31, 2006, approximately $10 million of this amount relates to 131 open claims presented to Generation, while the remaining $38 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

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 and for an additional two weeks relating to start up issues arising from the oil spill shutdown. The total shutdown period resulted 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. In January 2007, Exelon submitted a revised damages calculation to the Oil Spill Liability Trust Fund identifying approximately $21 million in specific damages and losses. As this matter represents a contingent gain, Generation has not recorded any income and expects this matter to be resolved in 2007.

Exelon and ComEd

ComEd Rate Case. ComEd requested recovery of amounts as part of its August 2005 Rate Case, which have previously been recorded as expense. Specifically, ComEd requested the following (all amounts pre-tax):

• recovery of approximately $87 million related to losses on extinguishment of long-term debt as part of ComEd’s 2004 Accelerated Liability Management Plan;

• recovery of $40 million of previously incurred MGP costs;

• recovery of $158 million of previously incurred severance costs; and

• recovery of $5 million of expenses previously incurred in the Procurement Case.

As discussed in Note 4—Regulatory Issues, ComEd received a final order from the ICC on July 26, 2006, which approved recovery of certain of these costs. Exelon and ComEd had anticipated recording a one-time benefit to reverse these prior charges and Exelon and ComEd did recognize a one-time benefit during the third quarter of 2006 of approximately $130 million (pre-tax) related to the losses on the extinguishment of long-term debt, MGP costs and Procurement Case costs where the recovery mechanism was specifically identified by the ICC final order. While ComEd believed the intent of the Rate Order was to allow ComEd recovery of the previously incurred severance costs through its administrative and general (A&G) expenses, ComEd requested clarification from the ICC on rehearing related to the amount of A&G expenses it should be allowed to recover. The ICC agreed to rehear ComEd’s A&G costs, as well as several other items referred to in Note 4—Regulatory Issues. In its December 20, 2006 order on rehearing, the ICC confirmed ComEd’s ability to recover the previously incurred severance costs, and ComEd recorded a regulatory asset of $158 million at that time.

Exelon

Pension Claim. On July 11, 2006, a former employee of ComEd filed a purported class action lawsuit against the Exelon Corporation Cash Balance Pension Plan (Plan) in the Federal District Court for the Northern District of Illinois. The complaint alleges that the Plan, which covers certain management employees of Exelon’s subsidiaries, calculated lump sum distributions in a manner that

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Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

does not comply with the Employee Retirement Income Security Act (ERISA). The plaintiff seeks compensatory relief from the Plan on behalf of participants who received lump sum distributions since 2001 and injunctive relief with respect to future lump sum distributions. It remains to be determined whether this case will proceed as a class action and how many Plan participants may be part of the proposed class, if a class is certified. However, the lawsuit is not expected to have a material financial impact on Exelon.

Savings Plan Claim. On September 11, 2006, five individuals claiming to be participants in the Exelon Corporation Employee Savings Plan, Plan #003 (Savings Plan), filed a putative class action lawsuit in the United States District Court for the Northern District of Illinois. The complaint names as defendants Exelon, its Director of Employee Benefit Plans and Programs, the Employee Savings Plan Investment Committee, the Compensation and the Risk Oversight Committees of Exelon’s Board of Directors and members of those committees. The complaint alleges that the defendants breached fiduciary duties under ERISA by, among other things, permitting fees and expenses to be incurred by the Savings Plan that allegedly were unreasonable and for purposes other than to benefit the Savings Plan and participants, and failing to disclose purported “revenue sharing” arrangements among the Savings Plan’s service providers. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Savings Plan and participants, including alleged investment losses. Exelon cannot determine the outcome of the above-described claim but the impact to Exelon’s results of operations could be material.

Exelon, Generation, ComEd and PECO

General. The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants 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 the Registrants’ financial condition, results of operations or cash flows.

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, Generation, ComEd and PECO 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 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. 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

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Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

December 31, 2006, 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 PECO Energy Capital, L.P. (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, 2006 and 2005, Exelon had retained earnings of $3.4 billion and $3.2 billion, respectively, which included Generation undistributed earnings of $1.8 billion and $1.0 billion, ComEd retained deficit of $(193) million and $(81) million, PECO retained earnings of $584 million and $649 million, respectively. At December 31, 2006 and 2005, Exelon’s common equity to total capitalization ratio was 43% and 39%, respectively. At December 31, 2006 and 2005, ComEd’s retained deficits included unappropriated retained deficits of $(1.6) billion and $(1.2) billion, respectively, partially offset by $1.4 billion and $1.1 billion, respectively, of retained earnings appropriated for future dividends.

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. 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. On August 31, 2006, the NRC provided PSEG with a letter restoring normal oversight levels regarding safety-conscious work environment issues, based on substantial and sustainable improvements in this area.

AmerGen Contingency Payment

In connection with the purchase of Unit No. 1 of the 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 $11 million had been accrued at December 31, 2006 and 2005, respectively. The amount accrued as of December 31, 2006 will be payable to the former owners of the TMI facility in the first quarter of 2007 and the amount accrued as of December 31, 2005 was paid in the first quarter of 2006. 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

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. 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 impacts 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. If a settlement is reached, 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 under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination” (EITF 93-7). Exelon cannot predict the timing of the final resolution of these refund claims.

In 2006, the Joint Committee on Taxation (Joint Committee) completed its review and granted approval for PECO’s income tax refund claims for investment tax credits. A majority of the investment tax credits claimed in the refund related to PECO’s formerly owned generation property. The asset transfer agreement between PECO and Generation provides that PECO retains all current tax and interest benefits associated with the refund claims. Thus, as a result of the agreement, PECO recorded the current tax and interest benefits and Generation recorded the remaining unamortized investment tax credits and the related future deferred tax effects. As a result, the investment tax credit refund and associated interest of $19 million (after tax) have been recorded as a credit in Exelon’s and PECO’s Consolidated Statements of Operations in 2006. Exelon and Generation recorded unamortized investment tax credits and related tax impacts of $10 million (after tax) as a charge to their Consolidated Statements of Operations. The unamortized investment tax credit recorded at Exelon, PECO and Generation will be amortized over the remaining depreciable book lives of the transmission, distribution and generation property using the deferral method pursuant to APB No. 2, “Accounting for the ‘Investment Credit’” and APB No. 4, “Accounting for the ‘Investment Credit’.” In addition, as a result of the approval of the refund claim, Exelon and PECO recorded a consulting expense of $3 million (after tax) in 2006. The net after-tax result of this settlement and consulting fees was $6 million, $16 million and $(10) million for Exelon, PECO and Generation, respectively.

In 2006, the IRS indicated to PECO that it agreed with a substantial portion of a research and development refund claim. This refund claim was subject to the approval of the Joint Committee. In 2006, the Joint Committee completed its review and granted approval of the research and development claim. A majority of the refund claim also related to PECO’s formerly owned generation property. Consistent with the investment tax credit refund claims, pursuant to the asset transfer agreement between PECO and Generation, PECO recorded the current tax and interest benefits and Generation recorded the future deferred tax effects. As a result, a research and development credit and the associated interest refund of $20 million (after tax) have been recorded as a credit in Exelon’s and PECO’s Consolidated Statements of Operations in 2006. Exelon and Generation recorded the future deferred tax impact of $11 million as a charge to their Consolidated Statements of Operations. In addition, based on the IRS’ indication of its agreement with a portion of the refund claim, PECO recorded an estimated tax consulting contingent fee of $2 million (after tax) during 2006. The net after-tax result of this settlement and consulting fees was $7 million, $18 million, and $(11) million for Exelon, PECO, and Generation respectively.

296

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Other Refund Claims. In 2001, ComEd and PECO filed requests with the IRS to change their tax method of accounting for certain capitalized overhead costs. To date, the IRS has not granted its consent to either ComEd or PECO to make that change and thus the requests remain pending. Thus far the IRS has sharply disagreed with the proposed method, despite that the fact that prior IRS guidance supports it. Recently the IRS informally indicated that it might issue settlement guidelines to bring resolution to the matter. ComEd and PECO are unable to estimate the ultimate outcome of any refund claims resulting from a settlement and will account for any amount received in the period the matter is settled with the IRS. ComEd and PECO have entered into an agreement with a tax consultant related to the filing of this tax accounting method change request. The fee for this agreement is contingent upon receiving consent and is based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash impacts to ComEd and PECO related to this agreement 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.

In addition, 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 93-7.

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 12—Income Taxes for further information.

19. Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

Supplemental Income Statement Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004.

For the Year Ended December 31, 2006	Exelon		Generation			ComEd		PECO
Operating revenues (a)
Wholesale	$	3,627	$	8,224		$	112	$	32
Retail electric and gas		11,318		813	(b)		5,590		4,920
Other		710		106			399		216
Total operating revenues	$	15,655	$	9,143		$	6,101	$	5,168

(a) Includes operating revenues from affiliates.

(b) Generation’s retail electric and gas operating revenues consist solely of Exelon Energy Company, LLC.

297

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2005	Exelon		Generation			ComEd		PECO
Operating revenues (a)
Wholesale	$	3,381	$	8,087		$	112	$	29
Retail electric and gas		11,305		857	(b)		5,776		4,680
Other		671		102			376		201
Total operating revenues	$	15,357	$	9,046		$	6,264	$	4,910

(a) Includes operating revenues from affiliates.

(b) Generation’s retail electric and gas operating revenues consist solely of Exelon Energy Company, LLC.

For the Year Ended December 31, 2004	Exelon		Generation			ComEd		PECO
Operating revenues (a)
Wholesale	$	3,275	$	6,979		$	101	$	34
Retail electric and gas		10,290		684	(b)		5,360		4,256
Other		568		40			342		197
Total operating revenues	$	14,133	$	7,703		$	5,803	$	4,487

(a) Includes operating revenues from affiliates.

(b) Generation’s retail electric and gas operating revenues consist solely of Exelon Energy Company, LLC.

For the Year Ended December 31, 2006	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment (a)	$	854	$	279	$	380	$	155
Regulatory assets		605		—		50		555
Nuclear fuel (b)		411		411		—		—
Asset retirement obligation accretion (c)		235		234		1		—
Amortization of intangible assets		27		—		—		—
Total depreciation, amortization and accretion	$	2,132	$	924	$	431	$	710

(a) Includes amortization of capitalized software costs.

(b) Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c) Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.

For the Year Ended December 31, 2005	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment (a)	$	816	$	254	$	368	$	157
Regulatory assets		454		—		45		409
Nuclear fuel (b)		385		385		—		—
Asset retirement obligation accretion (c)		243		243		—		—
Amortization of intangible assets		69		4		—		—
Total depreciation, amortization and accretion	$	1,967	$	886	$	413	$	566

(a) Includes amortization of capitalized software costs.

(b) Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c) Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.

298

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2004	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment (a)	$	835	$	294	$	366	$	144
Regulatory assets		418		—		44		374
Nuclear fuel (b)		380		381		—		—
Asset retirement obligation accretion (c)		210		210		—		—
Amortization of intangible assets		90		38		—		—
Total depreciation, amortization and accretion	$	1,933	$	923	$	410	$	518

(a) Includes amortization of capitalized software costs.

(b) Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c) Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.

For the Year Ended December 31, 2006	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility (a)	$	484	$	—	$	241	$	244
Real estate		154		112		30		12
Payroll		106		57		21		9
Other (b)		27		16		11		(3	)
Total taxes other than income	$	771	$	185	$	303	$	262

(a) Municipal and state utility taxes are also recorded in revenues on the Registrants’ Consolidated Statements of Operations.

(b) PECO reflects a reduction in tax accruals of $12 million related to sales and use tax and state franchise tax adjustments.

For the Year Ended December 31, 2005	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility (a)	$	477	$	—	$	247	$	230
Real estate		121		88		29		4
Payroll		103		54		21		9
Other (b)		27		28		6		(12	)
Total taxes other than income	$	728	$	170	$	303	$	231

(a) Municipal and state utility taxes are also recorded in revenues on the Registrants’ Consolidated Statements of Operations.

(b) PECO 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 Year Ended December 31, 2004	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility (a)	$	439	$	—	$	234	$	205
Real estate		146		107		29		10
Payroll		95		48		21		10
Other		30		11		7		11
Total taxes other than income	$	710	$	166	$	291	$	236

(a) Municipal and state utility taxes are also recorded in revenues on the Registrants’ Consolidated Statements of Operations.

299

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2006	Exelon			Generation			ComEd			PECO
Income (loss) in equity method investments
Financing trusts of ComEd and PECO (a)	$	(19	)	$	—		$	(10	)	$	(9	)
TEG and TEP (b)		(7	)		(7	)		—			—
Synthetic fuel-producing facilities		(83	)		—			—			—
NuStart Energy Development, LLC		(2	)		(2	)		—			—
Total income (loss) in equity method investments	$	(111	)	$	(9	)	$	(10	)	$	(9	)

(a) Financing trusts were deconsolidated as of December 31, 2003.

(b) Includes losses incurred after acquisition of a 49.5% interests in TEG and TEP in October 2004. On February 9, 2007, Generation sold its ownership interests in TEG and TEP. See Note 2—Acquisitions and Dispositions for additional information.

For the Year Ended December 31, 2005	Exelon			Generation			ComEd			PECO
Income (loss) in equity method investments
Financing trusts of ComEd and PECO (a)	$	(30	)	$	—		$	(14	)	$	(16	)
TEG and TEP (b)		(1	)		(1	)		—			—
Synthetic fuel-producing facilities		(104	)		—			—			—
Communications joint ventures and other investments		1			—			—			—
Total income (loss) in equity method investments	$	(134	)	$	(1	)	$	(14	)	$	(16	)

(a) Financing trusts were deconsolidated as of December 31, 2003.

(b) Includes losses incurred after acquisition of a 49.5% interests in TEG and TEP in October 2004. On February 9, 2007, Generation sold its ownership interests in TEG and TEP. See Note 2—Acquisitions and Dispositions for additional information.

For the Year Ended December 31, 2004	Exelon			Generation			ComEd			PECO
Income (loss) in equity method investments
Financing trusts of ComEd and PECO (a)	$	(44	)	$	—		$	(19	)	$	(25	)
Sithe (b)		(11	)		(11	)		—			—
TEG and TEP (d)		(3	)		(3	)		—			—
Synthetic fuel-producing facilities		(84	)		—			—			—
Affordable housing projects (c)		(9	)		—			—			—
Communications joint ventures and other investments		(3	)		—			—			—
Total income (loss) in equity method investments	$	(154	)	$	(14	)	$	(19	)	$	(25	)

(a) Financing trusts were deconsolidated as of December 31, 2003.

(b) 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.

(c) Prior to the sale of investments on October 15, 2004 and November 12, 2004.

(d) Includes losses incurred after acquisition of a 49.5% interests in TEG and TEP in October 2004. On February 9, 2007, Generation sold its ownership interests in TEG and TEP. See Note 2—Acquisitions and Dispositions for additional information.

300

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2006	Exelon			Generation			ComEd			PECO
Other, net
Investment income	$	8		$	—		$	2		$	6
Regulatory recovery of prior loss on extinguishment of long-term debt (a)		87			—			87			—
Gain on disposition of assets, net		3			—			1			1
Decommissioning-related activities
Decommissioning trust fund income (b)		150			150			—			—
Decommissioning trust fund income—AmerGen (b)		39			39			—			—
Other-than-temporary impairment of decommissioning trust funds (d)		(32	)		(32	)		—			—
Contractual offset to non-operating decommissioning-related activities (c)		(122	)		(122	)		—			—
Impairment of investments and other assets		(2	)		—			(2	)		—
Net direct financing lease income		23			—			—			—
AFUDC, equity		3			—			3			—
Recovery of tax credits related to Exelon’s investments in synthetic fuel-producing facilities		73			—			—			—
Interest income associated with investment tax credit and research and development credit refunds (e)		21			—			—			21
Other		15			6			5			2
Total other, net	$	266		$	41		$	96		$	30

(a) See Note 4—Regulatory Issues for further discussion of the loss on extinguishment of long-term debt. Recovery of these costs was granted in the July 26, 2006 ICC rate order.

(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 regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Note 13—Asset Retirement Obligations and Note 9—Fair Value of Financial Assets and Liabilities for more information regarding the regulatory accounting applied for certain nuclear units.

(d) Includes other-than-temporary impairments for 2006 totaling $29 million, $1 million and $2 million on nuclear decommissioning trust funds for the former ComEd units, the former PECO units and AmerGen units, respectively.

(e) See Note 18—Commitments and Contingencies for additional information.

301

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the Year Ended December 31, 2005	Exelon			Generation			ComEd			PECO
Other, net
Investment income	$	9		$	—		$	3		$	6
Gain on disposition of assets, net		12			—			6			6
Loss on settlement of cash-flow interest-rate swaps		—			—			(15	)		—
Decommissioning-related activities
Decommissioning trust fund income (a)		135			135			—			—
Decommissioning trust fund income—AmerGen (a)		77			77			—			—
Other-than-temporary impairment of decommissioning trust funds (c)		(22	)		(22	)		—			—
Contractual offset to non-operating decommissioning-related activities (b)		(115	)		(115	)		—			—
Net direct financing lease income		22			—			—			—
AFUDC, equity		7			—			5			2
Other		9			20			5			(1	)
Total other, net	$	134		$	95		$	4		$	13

(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—Asset Retirement Obligations and Note 9—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 and $2 million on nuclear decommissioning trust funds for the former ComEd units and AmerGen units, respectively.

For the Year Ended December 31, 2004	Exelon			Generation			ComEd			PECO
Other, net
Investment income	$	7		$	—		$	3		$	8
Net loss on early extinguishment of debt		(130	)		—			(130	)		—
Gain on disposition of assets, net (a)		111			85			3			9
Decommissioning-related activities
Decommissioning trust fund income (b)		194			194			—			—
Decommissioning trust fund income—AmerGen (b)		43			43			—			—
Other-than-temporary impairment of decommissioning trust funds (d)		(268	)		(268	)		—			—
Contractual offset to non-operating decommissioning-related activities (c)		66			66			—			—
Impairment of investments and other assets		(14	)		—			—			—
Net direct financing lease income		21			—			—			—
AFUDC, equity		4			—			3			1
Other		26			10			5			—
Total other, net	$	60		$	130		$	(116	)	$	18

(a) Generation includes $85 million gain on sale of Boston Generating. See Note 2—Acquisitions and Dispositions for additional information.

302

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

(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 regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Note 13—Asset Retirement Obligations and Note 9—Fair Value of Financial Assets and Liabilities for more information regarding the regulatory accounting applied for certain nuclear units.

(d) 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.

Supplemental Cash Flow Information

As a result of adopting FIN 47 as of December 31, 2005, Exelon, Generation, ComEd and PECO 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, $22 million, $5 million and $2 million resulted in a non-cash investing activity for Exelon, Generation, ComEd and PECO, respectively, as of December 31, 2005. See Note 13—Asset Retirement Obligations for additional information on the adoption of FIN 47. In addition to this non-cash activity, the following table provides additional information about the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004.

For the Year Ended December 31, 2006	Exelon			Generation			ComEd			PECO
Cash paid during the year
Interest (net of amount capitalized)	$	664		$	93		$	249		$	261
Income taxes (net of refunds)		1,044			633			344			383
Impairment charges
Impairment of goodwill	$	776		$	—		$	776		$	—
Impairment of intangible assets		115			—			—			—
Other		3			—			—			—
Total impairment charges	$	894		$	—		$	776		$	—
Other non-cash operating activities
Pension and non-pension postretirement benefits costs	$	258		$	114		$	72		$	30
Provision for uncollectible accounts		94			2			33			58
Equity in losses of unconsolidated affiliates		111			9			10			9
Other decommissioning-related activities		(131	)		(131	)		—			—
Amortization of energy related options		107			107			—			—
Amortization of deferred revenue		(86	)		(86	)		—			—
Spent nuclear fuel interest expense		44			44			—			—
Non-cash accounts receivable activity		(63	)		—			—			—
Write-off Merger-related capitalized costs (a)		46			—			—			—
2006 ICC rate orders (b)		(288	)		—			(288	)		—
Other		105			(6	)		39			12
Total other non-cash operating activities	$	197		$	53		$	(134	)	$	109

(a) Represents the Merger-related capitalized costs paid prior to 2006.

(b) See Note 4—Regulatory Issues.

303

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Changes in other assets and liabilities
Other current assets	$	(35	)	$	(59	)(a)	$	(6	)	$	47	(b)
Other noncurrent assets and liabilities		(201	)		(220	)(c)		5			2
Total change in other assets and liabilities	$	(236	)	$	(279	)	$	(1	)	$	49

(a) Relates primarily to the purchase of energy-related options and prepaid assets.

(b) Relates primarily to deferred/over-recovered energy costs.

(c) Relates primarily to the purchase of long-term fuel options.

Non-cash investing and financing activities
Change in asset retirement cost	$	393	$	393	$	—	$	—
Declaration of dividend not paid as of December 31, 2006		295		—		—		—
Purchase accounting adjustments		25		25		—		—
Resolution of certain tax matters and PECO/Unicom merger severance adjustment		5		—		5		—
Non-cash contribution from member		—		27		—		—

For the Year Ended December 31, 2005	Exelon			Generation			ComEd			PECO
Cash paid during the year
Interest (net of amount capitalized)	$	798		$	121		$	272		$	281
Income taxes (net of refunds)		378			242			278			430
Other non-cash operating activities
Pension and non-pension postretirement benefits costs	$	222		$	97		$	63		$	30
Provision for uncollectible accounts		77			—			24			45
Equity in losses of unconsolidated affiliates		134			1			14			16
Gains on sales of investments and wholly owned subsidiaries		(22	)		(24	)		—			—
Net realized gains on nuclear decommissioning trust funds		(49	)		(49	)		—			—
Other decommissioning-related activities		(15	)		(15	)		—			—
Amortization of energy related options		40			40			—			—
Other		36			(28	)		39			4
Total other non-cash operating activities	$	423		$	22		$	140		$	95
Changes in other assets and liabilities
Other current assets	$	(168	)	$	(148	)(a)	$	(10	)	$	(18	)(b)
Other noncurrent assets and liabilities		(211	)		(165	)(c)		(15	)		20
Total change in other assets and liabilities	$	(379	)	$	(313	)	$	(25	)	$	2

(a) Relates primarily to the purchase of energy-related options and prepaid assets.

(b) Relates primarily to deferred energy costs.

(c) Relates primarily to tolling agreement deferred revenue.

304

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Non-cash investing and financing activities
Change in asset retirement cost	$	251	$	251	$	—	$	—
Consolidation of the voluntary employee beneficiary association trust		34		—		—		—
Resolution of certain tax matters and PECO/Unicom merger severance adjustment		23		—		23		—
Purchase accounting adjustments		11		11		—		—
Sale of asset		4		4		—		—
Non-cash contribution from member		—		16		—		—

Impairment charges

For the year ended December 31, 2005, the impairment charges amount of $1.2 billion in Exelon’s and ComEd’s Consolidated Statements of Cash Flows relates to the impairment of goodwill.

For the Year Ended December 31, 2004	Exelon			Generation			ComEd			PECO
Cash paid during the year
Interest (net of amount capitalized)	$	888		$	163		$	357		$	298
Income taxes (net of refunds)		205			20			356			394
Other non-cash operating activities
Pension and non-pension postretirement benefits costs	$	310		$	128		$	97		$	37
Provision for uncollectible accounts		87			2			37			47
Equity in losses of unconsolidated affiliates		153			14			19			25
Gains on sales of investments and wholly owned subsidiaries		(162	)		(91	)		—			—
Net realized gains on nuclear decommissioning trust funds		(72	)		(72	)		—			—
Other decommissioning-related activities		169			169			—			—
Other		(24	)		(47	)		95			9
Total other non-cash operating activities	$	461		$	103		$	248		$	118
Changes in other assets and liabilities
Other current assets	$	46		$	22	(a)	$	7		$	18	(b)
Other noncurrent assets and liabilities		119			62	(c)		(34	)		(5	)
Total change in other assets and liabilities	$	165		$	84		$	(27	)	$	13

(a) Relates primarily to the purchase of energy-related options and prepaid assets.

(b) Relates primarily to deferred energy costs.

(c) Relates primarily to tolling agreement deferred revenue.

305

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Non-cash investing and financing activities
Change in asset retirement cost	$	829	$	829	$	—	$	—
Resolution of certain tax matters and PECO/Unicom merger severance adjustment		14		—		14		—
Purchase accounting adjustments		36		22		—		—
Disposition of Boston Generating (a)		102		102		—		—
Note cancelled in conjunction with the acquisition of Sithe International from Sithe		92		92		—		—
Consolidation of Sithe pursuant to FIN 46-R		85		85		—		—
Non-cash issuance of common stock		26		—		—		—
Issuance of note payable to acquire synthetic fuel interests		22		—		—		—
Capital lease obligations		1		1		—		—
Non-cash distribution to member		—		4		—		—

(a) See Note 2—Acquisitions and Dispositions for additional information regarding the disposition of Boston Generating.

Impairment charges

For the year ended December 31, 2004, $10 million of the $11 million impairment charges amount in Exelon’s Consolidated Statements of Cash Flows relates to the impairment of investments held by Exelon.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants’ as of December 31, 2006 and 2005.

December 31, 2006	Exelon		Generation		ComEd		PECO
Investments
Equity method investments:
Direct financing leases	$	529	$	—	$	—	$	—
Financing trusts (a)		84		—		20		64
TEG and TEP (b)		81		81		—		—
Keystone (d)		8		8		—		—
Conemaugh (e)		7		7		—		—
NuStart Energy Development, LLC		1		1		—		—
Total equity method investments		710		97		20		64
Other investments:
Employee benefit trusts and investments(c)		97		15		44		21
Other		3		3		—		—
Total investments	$	810	$	115	$	64	$	85

(a) Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2006 pursuant to the provisions of FIN 46-R. See Note 1—Significant Accounting Policies for further discussion of the effects of FIN 46-R.

(b) Generation acquired 49.5% interests in two facilities in Mexico on October 13, 2004, and on February 9, 2007, Generation sold its ownership interests in TEG and TEP. See Note 2—Acquisitions and Dispositions for additional information.

(c) The Registrants’ investments in these marketable securities are recorded at fair market value.

(d) Keystone Fuels, LLC (Keystone)

(e) Conemaugh Fuels, LLC (Conemaugh)

306

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

December 31, 2005	Exelon		Generation		ComEd		PECO
Investments
Equity method investments:
Direct financing leases	$	507	$	—	$	—	$	—
Financing trusts (a)		107		—		34		73
TEG and TEP (b)		90		90		—		—
Keystone		7		7		—		—
Conemaugh		6		6		—		—
Energy services and other ventures		4		2		—		2
Total equity method investments		721		105		34		75
Other investments:
Employee benefit trusts and investments(c)		92		15		41		20
Total investments	$	813	$	120	$	75	$	95

(a) Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2006 pursuant to the provisions of FIN 46-R. See Note 1—Significant Accounting Policies for further discussion of the effects of FIN 46-R.

(b) Generation acquired 49.5% interests in two facilities in Mexico on October 13, 2004, and on February 9, 2007, Generation sold its ownership interests in TEG and TEP. See Note 2—Acquisitions and Dispositions for additional information.

(c) The Registrants’ investments in these marketable securities are recorded at fair market value.

Like-Kind Exchange Transaction (Exelon). 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 leases. The remaining payments are payable at the end of the thirty-year leases 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,
	2006		2005
Total minimum lease payments	$	1,492	$	1,492
Less: unearned income		963		985
Net investment in direct financing leases	$	529	$	507

307

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides additional information about liabilities of the Registrants’ at December 31, 2006 and 2005.

December 31, 2006	Exelon		Generation		ComEd		PECO
Accrued expenses
Compensation-related accruals (a)	$	419	$	222	$	82	$	27
Taxes accrued		365		206		120		63
Interest accrued		307		17		254		23
Severance accrued		34		10		6		2
Other accrued expenses		55		41		5		6
Total accrued expenses	$	1,180	$	496	$	467	$	121

(a) Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

December 31, 2005	Exelon		Generation		ComEd		PECO
Accrued expenses
Compensation-related accruals (a)	$	377	$	188	$	85	$	26
Taxes accrued		256		147		106		42
Interest accrued		258		15		209		20
Severance accrued		22		7		8		1
Other accrued expenses		92		58		9		3
Total accrued expenses	$	1,005	$	415	$	417	$	92

(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, 2006 and 2005.

December 31, 2006	Exelon		Generation
Other current assets
Counterparty collateral deposits paid	$	26	$	26
Option premiums		179		179
Other current liabilities
Counterparty collateral deposits received		273		273

December 31, 2005	Exelon		Generation
Other current assets
Counterparty collateral deposits paid	$	285	$	285
Other current liabilities
Counterparty collateral deposits received		101		101

308

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides additional information about accumulated other comprehensive income (loss) recorded (after tax) within Exelon’s Consolidated Balance Sheets as of December 31, 2006 and 2005.

December 31, 2006	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Minimum pension liability	$	(224	)	$	—		$	—		$	—
Adjustment to initially apply SFAS No. 158		(1,302	)		(1	)		—			—
Net unrealized gain (loss) on cash-flow hedges		222			247			(4	)		5
Unrealized gain on marketable securities		169			167			1			—
State income tax rate alignment		(2	)		—			—			—
Total accumulated other comprehensive income (loss)	$	(1,137	)	$	413		$	(3	)	$	5

December 31, 2005	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Minimum pension liability	$	(1,362	)	$	—		$	—		$	—
Net unrealized gain (loss) on cash-flow hedges		(337	)		(318	)		—			7
Unrealized gain (loss) on marketable securities		75			76			(1	)		—
Total accumulated other comprehensive income (loss)	$	(1,624	)	$	(242	)	$	(1	)	$	7

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of December 31, 2006 and 2005.

December 31, 2006	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	2,982	$	—	$	2,982
Pension and other postretirement benefits		1,380		—		—
Deferred income taxes		801		11		790
Debt costs		209		179		30
Severance		158		158		—
Conditional asset retirement obligations		109		95		14
MGP remediation costs		73		47		26
Non-pension postretirement benefits		39		—		39
Rate case costs		7		7		—
DOE facility decommissioning		6		—		6
Procurement case costs		5		5		—
Other		39		30		9
Total regulatory assets	$	5,808	$	532	$	3,896

309

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

December 31, 2006	Exelon		ComEd		PECO
Regulatory liabilities
Nuclear decommissioning	$	1,911	$	1,760	$	151
Removal costs		1,059		1,059		—
Other		5		5		—
Noncurrent regulatory liabilities		2,975		2,824		151
Over-recovered energy costs current liability		6		—		6
Total regulatory liabilities	$	2,981	$	2,824	$	157
December 31, 2005	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	3,532	$	—	$	3,532
Deferred income taxes		789		8		781
Debt costs		142		107		35
Conditional asset retirement obligations		104		91		13
Non-pension postretirement benefits		45		—		45
Recoverable transition costs		43		43		—
MGP remediation costs		26		—		26
DOE facility decommissioning		13		—		13
Other		40		31		9
Noncurrent regulatory assets		4,734		280		4,454
Deferred energy costs current asset		39		—		39
Total regulatory assets	$	4,773	$	280	$	4,493
December 31, 2005	Exelon		ComEd		PECO
Regulatory liabilities
Nuclear decommissioning	$	1,503	$	1,435	$	68
Removal costs		1,015		1,015		—
Total regulatory liabilities	$	2,518	$	2,450	$	68

CTCs. 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 CTCs include 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%.

Pension and other postretirement benefits. This amount represents regulatory assets related to the recognition of the underfunded status of Exelon’s defined benefit postretirement plans as a liability on its balance sheet in accordance with SFAS No. 158. The regulatory asset is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses attributable to ComEd’s pension plan and ComEd’s and PECO’s other postretirement benefit plans determined by the cost recognition provisions of SFAS No. 87 and SFAS No. 106. Exelon believes it is probable that these items will be recovered through rates by ComEd and PECO in future periods. See Note 14—Retirement Benefits for further detail.

310

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

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. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding. Recovery of early debt retirement costs, which will be amortized over the life of the related retired debt, was granted to ComEd in the July 26, 2006 ICC rate order. See Note 4—Regulatory Issues.

Severance costs. These costs represent previously incurred severance costs that ComEd was granted recovery of in the December 20, 2006 ICC rehearing order. Recovery is over 7.5 years. See Note 4—Regulatory Issues.

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 13—Asset Retirement Obligations for further information.

MGP remediation costs. Recovery of these items was granted to ComEd in the July 26, 2006 ICC rate order. See Note 4—Regulatory Issues. For PECO, these costs represent estimated MGP-related environmental remediation costs at PECO which are recoverable through regulated gas rates. The period of recovery will depend on the timing of the actual expenditures.

Non-pension postretirement benefits. These costs at PECO are the result of transitioning to SFAS No. 106 in 1993, which are recoverable in rates through 2012.

Rate case costs. Recovery of these items was granted to ComEd in the July 26, 2006 ICC rate order. Recovery is over three years. See Note 4—Regulatory Issues.

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.

Procurement case costs. Recovery of these items was granted to ComEd in the July 26, 2006 ICC rate order. Recovery is over three years. See Note 4—Regulatory Issues.

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—Asset Retirement Obligations for further information.

311

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Removal costs. These amounts represent funds received from customers to cover the future removal of property, plant and equipment.

Deferred (over-recovered) energy costs current asset (liability). These costs represent fuel costs recoverable (refundable) under PECO’s purchase gas adjustment clause.

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 fully recovered these charges by the end of 2006. See Note 4—Regulatory Issues for discussion of recoverable transition cost amortization.

The regulatory assets related to pension and other postretirement benefit plans, deferred income taxes, non-pension postretirement benefits, MGP remediation, severance, Procurement Case and Rate Case are not earning a rate of return. Recovery of the regulatory assets for conditional asset retirement obligations, debt costs, recoverable transition costs, DOE facility decommissioning and deferred energy costs are earning a rate of return.

20. Segment Information (Exelon, Generation, ComEd and PECO)

Exelon has three operating segments: Generation, ComEd and PECO. Exelon evaluates the performance of its business segments based on net income. An analysis and reconciliation of Exelon’s operating segment information to the respective information in the consolidated financial statements are as follows:

	Generation		ComEd		PECO		Other (a)		Intersegment Eliminations			Consolidated
Total revenues (b):
2006	$	9,143	$	6,101	$	5,168	$	807	$	(5,564	)	$	15,655
2005		9,046		6,264		4,910		694		(5,557	)		15,357
2004		7,703		5,803		4,487		670		(4,530	)		14,133
Intersegment revenues:
2006	$	4,742	$	7	$	8	$	807	$	(5,564	)	$	—
2005		4,848		8		8		693		(5,557	)		—
2004		3,841		18		9		669		(4,537	)		—
Depreciation and amortization:
2006	$	279	$	430	$	710	$	68	$	—		$	1,487
2005		254		413		566		101		—			1,334
2004		286		410		518		81		—			1,295
Operating expenses (b):
2006	$	6,747	$	5,546	$	4,302	$	1,103	$	(5,564	)	$	12,134
2005		7,194		6,276		3,861		859		(5,557	)		12,633
2004		6,664		4,186		3,473		842		(4,531	)		10,634
Interest expense, net:
2006	$	159	$	308	$	266	$	152	$	(5	)	$	880
2005		128		291		279		131		—			829
2004		103		349		303		61		12			828

312

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

	Generation			ComEd			PECO			Other (a)			Intersegment Eliminations			Consolidated
Income taxes:
2006	$	866		$	445		$	180		$	(285	)	$	—		$	1,206
2005		709			363			247			(375	)		—			944
2004		401			457			249			(394	)		—			713
Income (loss) from continuing operations
2006	$	1,403		$	(112	)	$	441		$	(142	)	$	—		$	1,590
2005		1,109			(676	)		520			(2	)		—			951
2004		657			676			455			82			—			1,870
Income (loss) from discontinued operations
2006	$	4		$	—		$	—		$	(2	)	$	—		$	2
2005		19			—			—			(5	)		—			14
2004		(16	)		—			—			(13	)		—			(29	)
Cumulative effect of changes in accounting principles:
2006	$	—		$	—		$	—		$	—		$	—		$	—
2005		(30	)		(9	)		(3	)		—			—			(42	)
2004		32			—			—			(9	)		—			23
Net income (loss):
2006		$1,407		$	(112	)	$	441		$	(144	)	$	—		$	1,592
2005		1,098			(685	)		517			(7	)		—			923
2004		673			676			455			60			—			1,864
Capital expenditures:
2006		$1,109		$	911		$	345		$	53		$	—		$	2,418
2005		1,067			776			298			24			—			2,165
2004		960			721			225			15			—			1,921
Total assets:
2006		$18,909		$	17,774		$	9,773		$	14,295		$	(16,432	)		$44,319
2005		17,724			17,491			10,086			13,079			(15,583	)		42,797

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

(b) Utility taxes of $241 million, $247 million and $234 million are included in revenues and expenses for 2006, 2005 and 2004, respectively, for ComEd. Utility taxes of $244 million, $230 million and $205 million are included in revenues and expenses for 2006, 2005 and 2004, respectively, for PECO.

21. Related Party Transactions (Exelon, Generation, ComEd and PECO)

Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding, ComEd Funding Trust, PETT, PECO Energy Capital Corporation 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.

313

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon

The financial statements of Exelon include related-party transactions as presented in the tables below:

	For the Years Ended December 31,
	2006			2005			2004
Operating revenues from affiliates
ComEd Transitional Funding Trust	$	3		$	3		$	3
PETT		7			9			10
Total operating revenues from affiliates	$	10		$	12		$	13
Interest expense to affiliates, net
ComEd Transitional Funding Trust	$	47		$	66		$	85
ComEd Financing II		13			13			13
ComEd Financing III		13			13			13
PETT		180			212			235
PECO Trust III		6			6			6
PECO Trust IV		6			6			6
Other		(1	)		—			(1	)
Total interest expense to affiliates, net	$	264		$	316		$	357
Equity in earnings (losses) of unconsolidated affiliates
ComEd Funding LLC	$	(10	)	$	(14	)	$	(20	)
ComEd Financing III		—			—			1
PETT		(9	)		(16	)		(25	)
TEG and TEP		(7	)		(1	)		(3	)
Sithe		—			—			(11	)
Investment in synthetic fuel-producing facilities		(83	)		(104	)		(84	)
Affordable housing		—			—			(9	)
Other		(2	)		1			(3	)
Total equity in earnings (losses) of unconsolidated affiliates	$	(111	)	$	(134	)	$	(154	)

314

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

	December 31,
	2006		2005
Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	17	$	14
Investments in affiliates
ComEd Funding LLC		4		18
ComEd Financing II		10		10
ComEd Financing III		6		6
PETT		54		63
PECO Energy Capital Corporation		4		4
PECO Trust IV		6		6
TEG and TEP		81		90
NuStart Energy Development, LLC		1		2
Other		1		1
Total investment in affiliates	$	167	$	200
Receivable from affiliates (noncurrent)
ComEd Transitional Funding Trust	$	14	$	12
Payables to affiliates (current)
ComEd Transitional Funding Trust		—		1
ComEd Financing II		6		6
ComEd Financing III		4		4
PECO Trust III		1		1
Total payables to affiliates (current)	$	11	$	12
Long-term debt to ComEd Transitional Funding Trust, PETT and other financing trusts (including due within one year)
ComEd Transitional Funding Trust	$	648	$	987
ComEd Financing II		155		155
ComEd Financing III		206		206
PETT		2,403		2,976
PECO Trust III		81		81
PECO Trust IV		103		103
Total long-term debt due to financing trusts	$	3,596	$	4,508

315

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation

The financial statements of Generation include related-party transactions as presented in the tables below:

	For the Years Ended December 31,
	2006			2005			2004
Operating revenues from affiliates
ComEd (a)	$	2,929		$	3,174		$	2,374
PECO (a)		1,812			1,672			1,465
BSC (b)		1			2			2
Total operating revenues from affiliates	$	4,742		$	4,848		$	3,841
Purchased power from affiliates
ComEd (c)	$	—		$	—		$	9
Fuel from affiliates
PECO (c)		1			1			1
Operating and maintenance from affiliates
ComEd (c)		7			8			8
PECO (c)		7			7			8
BSC (b)		250			222			223
Total operating and maintenance from affiliates	$	264		$	237		$	239
Interest expense to affiliates, net
Exelon intercompany money pool (d)	$	4		$	3		$	3
Equity in earnings (losses) of unconsolidated affiliates
Sithe	$	—		$	—		$	(11	)
TEG and TEP		(7	)		(1	)		(3	)
NuStart Energy Development, LLC		(2	)		—			—
Total equity in earnings (losses) of unconsolidated affiliates	$	(9	)	$	(1	)	$	(14	)
Cash distribution paid to member	$	609		$	857		$	662
Cash contribution received from member		25			843			17

316

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

	December 31,
	2006		2005
Investments in affiliates
TEG and TEP	$	81	$	90
Keystone		8		7
Conemaugh		7		6
NuStart Energy Development, LLC		1		2
Total investment in affiliates	$	97	$	105
Receivables from affiliates (current)
Exelon (g)	$	85	$	—
ComEd (a)		197		242
ComEd decommissioning (e)		—		11
PECO (a)		153		151
BSC (b)		2		7
Total receivables from affiliates (current)	$	437	$	411
Contributions to Exelon intercompany money pool (d)	$	13	$	—
Payable to affiliate (current)
Exelon (g)	$	—	$	4
Borrowings from Exelon intercompany money pool (d)	$	—	$	92
Payables to affiliates (noncurrent)
ComEd decommissioning (f)	$	1,760	$	1,435
PECO decommissioning (f)		151		68
Total payables to affiliates (noncurrent)	$	1,911	$	1,503

(a) Generation has PPAs with ComEd and PECO, as amended, to provide the full energy requirements of ComEd and PECO. Generation’s PPA with ComEd expired December 31, 2006. As a result of the expiration of the PPA and the results of the auctions, beginning in 2007, Generation is selling more power through bilateral agreements with other new and existing counterparties. See Note 18 of the Combined Notes to Consolidated Financial Statements for further detail. Effective April 1, 2004, Generation entered into a one-year gas supply agreement with PECO.

(b) Generation receives a variety of corporate support services from 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.

(c) Generation purchases retail electric and ancillary services from ComEd and buys power from PECO for Generation’s own use. 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. Generation’s PPA with ComEd expired December 31, 2006. See Note 18 of the Combined Notes to Consolidated Financial Statements for further detail regarding the PPAs.

(d) 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.

(e) Generation had a receivable from ComEd representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation. This was fully paid in 2006.

(f) 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—Asset Retirement Obligations for additional information.

(g) In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation. In addition, Generation has a receivable from Exelon for the allocation of tax benefits related to the capital loss carryback. The December 31, 2005 payable from Exelon for the allocation of tax benefits was settled in 2006. See Note 12—Income Taxes for additional information.

317

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd

The financial statements of ComEd include related-party transactions as presented in the tables below:

	For the Years Ended December 31,
	2006			2005			2004
Operating revenues from affiliates
Generation (a)	$	7		$	8		$	17
Enterprises (a)		—			—			1
ComEd Transitional Funding Trust		3			3			3
Total operating revenues from affiliates	$	10		$	11		$	21
Purchased Power from affiliate
PPA with Generation (b)	$	2,929		$	3,174		$	2,374
Operation and maintenance from (to) affiliates
BSC (c)	$	220		$	193		$	192
Interest expense to affiliates, net
ComEd Transitional Funding Trust	$	47		$	66		$	85
ComEd Financing II		13			13			13
ComEd Financing III		13			13			13
UII (d)		—			—			(16	)
Exelon intercompany money pool (e)		—			(3	)		(3	)
Other		(1	)		(1	)		(1	)
Total interest expense to affiliates, net	$	72		$	88		$	91
Equity in earnings (losses) of unconsolidated affiliates
ComEd Funding LLC	$	(10	)	$	(14	)	$	(20	)
ComEd Financing III		—			—			1
Total equity in earnings (losses) of unconsolidated affiliates	$	(10	)	$	(14	)	$	(19	)
Capitalized costs
BSC (c)	$	81		$	62		$	62
Cash dividends paid to parent	$	—		$	498		$	457
Cash contributions received from parent		37			834			175

318

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

	December 31,
	2006		2005
Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	17	$	14
Exelon (h)		—		23
Other		1		—
Total receivables from affiliates (current)	$	18	$	37
Investment in affiliates
ComEd Funding LLC	$	4	$	18
ComEd Financing II		10		10
ComEd Financing III		6		6
Total investment in affiliates	$	20	$	34
Receivable from affiliates (noncurrent)
Generation (f)	$	1,760	$	1,435
ComEd Transitional Funding Trust		14		12
Total receivable from affiliates (noncurrent)	$	1,774	$	1,447
Payables to affiliates (current)
Generation decommissioning (g)	$	—	$	11
Generation (a)(b)		197		242
BSC (c)		10		14
ComEd Transitional Funding Trust		—		1
ComEd Financing II		6		6
ComEd Financing III		4		4
Other		2		—
Total payables to affiliates (current)	$	219	$	278
Borrowings from Exelon intercompany money pool (e)	$	—	$	140
Long-term debt to ComEd Transitional Funding Trust and other financing trusts (including due within one year)
ComEd Transitional Funding Trust	$	648	$	987
ComEd Financing II		155		155
ComEd Financing III		206		206
Total long-term debt due to financing trusts	$	1,009	$	1,348

(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’s full-requirements PPA, as amended, with Generation expired December 31 2006. See Note 18—Commitments and Contingencies for more information regarding the PPA.

(c) ComEd receives a variety of corporate support services from 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.

319

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

(d) ComEd had a note and interest receivable with a variable rate equal to 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.

(e) ComEd participated in Exelon’s intercompany money pool. ComEd earned interest on its contributions to the money pool and paid interest on its borrowings from the money pool at a market rate of interest. As of January 10, 2006, ComEd suspended participation in the intercompany money pool.

(f) 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—Asset Retirement Obligations for additional information.

(g) ComEd had a payable to Generation representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation. This was fully paid in 2006.

(h) The December 31, 2005 receivable from Exelon for the allocation of tax benefits was settled in 2006. See Note 12 – Income Taxes for additional information.

PECO

The financial statements of PECO include related-party transactions as presented in the tables below:

	For Year Ended December 31,
	2006			2005			2004
Operating revenues from affiliates
Generation (a)	$	8		$	8		$	9
PETT (b)		7			9			10
Total operating revenues from affiliates	$	15		$	17		$	19
Purchased power from affiliate
Generation (c)	$	1,811		$	1,670		$	1,447
Fuel from affiliate
Generation (d)		—			1			17
Operating and maintenance from affiliates
BSC (e)		129			108			106
Generation		1			1			1
Total operating and maintenance from affiliates	$	130		$	109		$	107
Interest expense to affiliates, net
PETT	$	180		$	212		$	235
PECO Trust III		6			6			6
PECO Trust IV		6			6			6
Other		1			(1	)		—
Total interest expense to affiliates, net	$	193		$	223		$	247
Equity in losses of unconsolidated affiliates
PETT	$	(9	)	$	(16	)	$	(25	)
Capitalized costs
BSC (e)	$	54		$	41		$	22
Cash dividends paid to parent	$	502		$	469		$	391
Cash contributions received from parent		181			250			312

320

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

	December 31,
	2006		2005
Receivable from affiliate (current)
Exelon	$	—	$	13
Contributions to Exelon intercompany money pool (f)		—		8
Investment in affiliates
PETT		54		63
PECO Energy Capital Corporation		4		4
PECO Trust IV		6		6
Total investment in affiliates	$	64	$	73
Receivable from affiliate (noncurrent)
Generation decommissioning (g)	$	151	$	68
Borrowings from Exelon intercompany money pool (f)	$	45	$	—
Payables to affiliates (current)
Generation (c)	$	153	$	151
BSC (e)		48		26
Exelon		1		—
PECO Trust III		1		1
Total payables to affiliates (current)	$	203	$	178
Long-term debt to PETT and other financing trusts (including due within one year)
PETT	$	2,404	$	2,975
PECO Trust III		81		81
PECO Trust IV		103		103
Total long-term debt to financing trusts	$	2,588	$	3,159
Shareholders’ equity—receivable from parent (h)	$	1,090	$	1,232

(a) PECO provides energy to Generation for Generation’s own use.

(b) PECO receives a monthly service fee from PETT based on a percentage of the outstanding balance of all series of transition bonds.

(c) PECO has entered into a PPA with Generation. See Note 18—Commitments and Contingencies for more information regarding the PPA.

(d) Effective April 1, 2004, PECO entered into a one-year gas procurement agreement with Generation.

(e) PECO receives a variety of corporate support services from 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.

(f) PECO participates in Exelon’s intercompany money pool. PECO 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.

(g) 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 13—Asset Retirement Obligations.

(h) 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 2007 through 2010.

321

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

22. Quarterly Data (Unaudited) (Exelon, Generation, ComEd and PECO)

Exelon

The data shown below includes 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)
	2006		2005		2006		2005			2006			2005			2006			2005
Quarter ended:
March 31	$	3,861	$	3,561	$	818	$	931		$	400		$	521		$	400		$	521
June 30		3,697		3,484		1,202		897			644			514			644			514
September 30 (a)		4,401		4,473		438		1,312			(44	)		725			(44	)		725
December 31 (a)		3,696		3,838		1,063		(416	)		592			(795	)		592			(837	)

(a) Results of operations for the third quarter of 2006 and the fourth quarter of 2005 included a $776 million and $1.2 billion, respectively, impairment of ComEd’s goodwill.

	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
	2006	2005	2006			2005			2006			2005
Quarter ended:
March 31	669	666	$	0.60		$	0.78		$	0.60		$	0.78
June 30	670	670		0.96			0.77			0.96			0.77
September 30 (a)	671	670		(0.07	)		1.08			(0.07	)		1.08
December 31 (a)	672	668		0.88			(1.19	)		0.88			(1.25	)

(a) Results of operations for the third quarter of 2006 and the fourth quarter of 2005 included a $776 million and $1.2 billion, respectively, 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
	2006	2005	2006			2005			2006			2005
Quarter ended:
March 31	675	675	$	0.59		$	0.77		$	0.59		$	0.77
June 30	676	677		0.95			0.76			0.95			0.76
September 30 (a)	671	677		(0.07	)		1.07			(0.07	)		1.07
December 31 (a)	677	668		0.87			(1.19	)		0.87			(1.25	)

(a) Results of operations for the third quarter of 2006 and the fourth quarter of 2005 included a $776 million and $1.2 billion, respectively, impairment of ComEd’s goodwill.

322

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

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

	2006								2005
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	63.62	$	61.98	$	58.86	$	59.90	$	56.00	$	57.46	$	52.01	$	47.18
Low price		57.83		56.74		51.13		52.79		46.62		49.60		44.14		41.77
Close		61.89		60.54		56.83		52.90		53.14		53.44		51.33		45.89
Dividends		0.400		0.400		0.400		0.400		0.400		0.400		0.400		0.400

Generation

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
	2006		2005		2006		2005		2006		2005		2006		2005
Quarter ended:
March 31		$2,220	$	2,020	$	468	$	506	$	268	$	320	$	268	$	320
June 30		2,214		2,105		818		456		500		296		500		296
September 30		2,635		2,711		668		575		394		335		394		335
December 31		2,074		2,210		443		316		245		177		245		147

ComEd

The data shown below includes all adjustments that 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)
	2006		2005		2006			2005			2006			2005			2006			2005
Quarter ended:
March 31	$	1,426	$	1,386	$	169		$	188		$	54		$	70		$	54		$	70
June 30		1,453		1,488		292			254			127			109			127			109
September 30 (a)		1,840		1,948		(338	)		463			(506	)		224			(506	)		224
December 31 (a)		1,381		1,442		432			(919	)		213			(1,079	)		213			(1,088	)

(a) Results of operations for the third quarter of 2006 and the fourth quarter of 2005 included a $776 million and $1.2 billion, respectively, impairment of goodwill.

323

Exelon Corporation and Subsidiary Companies

Exelon Generation Company, LLC and Subsidiary Companies

Commonwealth Edison Company and Subsidiary Companies

PECO Energy Company and Subsidiary Companies

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO

The data shown below includes all adjustments that PECO 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 on Common Stock
	2006		2005		2006		2005		2006		2005		2006		2005
Quarter ended:
March 31	$	1,407	$	1,295	$	210	$	274	$	93	$	129	$	92	$	128
June 30		1,148		1,044		205		225		93		110		92		109
September 30		1,379		1,322		237		320		134		166		133		165
December 31		1,235		1,249		213		231		121		115		120		111

23. Subsequent Events

On January 15, 2007, ComEd paid $145 million to retire its 7.650% notes at maturity.

324

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Exelon, Generation, ComEd, and PECO

None.

ITEM 9A. CONTROLS AND PROCEDURES

Exelon, Generation, ComEd, and PECO

During the fourth quarter of 2006, 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, 2006, 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, 2006. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2006 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.

On October 13, 2006, PECO completed the Common Customer System project, which moved the PECO customer accounts into the existing ComEd customer information management system (CIMS) to provide a common customer billing system for Exelon. This implementation impacted various processes and controls, which were tested as part of management’s assessment and report on the effectiveness of its internal control over financial reporting as of December 31, 2006 as discussed above.

ITEM 9B. OTHER INFORMATION

Exelon

None.

325

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

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, 2006.

Directors, Director Nomination Process, and Audit Committee

The information required under ITEM 10 concerning directors and nominees for election as directors at Exelon’s annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)) and the audit committee (Item 407(d)(4) and (d)(5) is incorporated herein by reference to information to be contained in Exelon’s definitive 2007 proxy statement (2007 Exelon Proxy Statement) to be filed with the SEC before April 29, 2007 pursuant to Regulation 14A under the Securities Exchange Act of 1934.

Code of Ethics

Exelon’s Code of Business Conduct is the code of ethics that applies to Exelon’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Senior Vice President, Corporate Governance 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 2006.

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, 2006.

Directors

Generation operates as a limited liability company and has no board of directors.

326

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 to be incorporated by reference to the 2007 Exelon Proxy Statement.

Code of Ethics

The Exelon Code of Business Conduct is the code of ethics that applies to all officers and employees of Generation. See discussion of Exelon’s Code of Ethics above.

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, 2006.

Directors

Frank M. Clark. Age 61. 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. Also a director of Aetna, Inc. and Waste Management, Inc.

James W. Compton. Age 69. Director of Commonwealth Edison Company since September 18, 2006. Chicago Urban League President and Chief Executive Officer from 1978 through 2006; Chicago Urban League Development Corporation President and Chief Executive Officer.

Sue L. Gin. Age 65. Director of Commonwealth Edison Company since November 28, 2005. Member of the audit committee. Founder, Owner, Chairman and Chief Executive Officer of Flying Food Group, LLC (in-flight catering company). Other directorships: Centerplate, Inc. She is also a director of Exelon.

Edgar D. Jannotta. Age 75. Director of Commonwealth Edison Company since November 28, 2005. Member of the audit committee. Chairman of William Blair & Company, L.L.C. (investment banking and brokerage company) since March 2001. Senior Director from 1996 through February 2001. Also a director of Aon Corporation and Molex, Inc. He is also a director of Exelon.

Edward J. Mooney. Age 65. Director of Commonwealth Edison Company since October 16, 2006. Former Delegue General-North America of Suez Lyonnaise, and former chairman and chief executive officer of Nalco Chemical Company since March 2000. Also a director of Northern Trust Corporation, FMC Corporation, FMC Technologies, Inc. and Cabot Microelectronics Corporation.

John W. Rogers, Jr. Age 49. Director of Commonwealth Edison Company since November 28, 2005. Chair of the audit committee. Founder, Chairman and CEO of Ariel Capital Management, Inc., LLC (an institutional money management firm). Also a director of Aon Corporation and McDonalds Corporation. He is also a director of Exelon.

Jesse H. Ruiz. Age 42. Director of Commonwealth Edison Company since October 16, 2006. Partner at the law firm Garden Carton & Douglas; Chairman of the Illinois State Board of Education.

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Richard L. Thomas. Age 76. Director of Commonwealth Edison Company since November 28, 2005. Member of the audit committee. Retired Chairman of First Chicago NBD Corporation (banking and financial services) and the First National Bank of Chicago. Also a director of SABRE Holdings Corporation. He is also a director of Exelon.

Audit Committee

The ComEd audit committee consists of John W. Rogers, Jr., its Chair, Sue L. Gin, Edgar D. Jannotta and Richard L. Thomas. Although ComEd is a controlled subsidiary of Exelon and is accordingly not required to have an audit committee, the ComEd board established an audit committee for the limited purpose of reviewing financial disclosures. The other ordinary functions of an audit committee, including oversight of the independent accountant, are carried out by the audit committee of the Exelon board of 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 See discussion of Exelon’s Code of Ethics above.

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, 2006.

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 61. Director and Chief Executive Officer of Exelon Corporation since October 20, 2000; Chairman since April 2002; President from October 20, 2000 through May 2003 and from November 2004 to the present. Former Chairman, President and CEO of Unicom Corporation and Commonwealth Edison Company. Former President and CEO of New England Electric System. Also a director of The Northern Trust Company and Sunoco, Inc.

Denis P. O’Brien. Age 46. 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 56. Director since March 15, 2004. Executive Vice President of Exelon Corporation since February 1, 2004. President and CEO of Exelon Energy Delivery and Exelon Generation. 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,

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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.

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 to be incorporated by reference to the 2007 Exelon Proxy Statement.

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. See discussion of Exelon’s Code of Ethics above.

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.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Objectives of the Compensation Program

The compensation committee reviews, administers and oversees executive compensation and employee benefit plans and programs, including annual and long-term incentives and executive compensation policies. The compensation committee makes recommendations to the independent directors regarding the compensation of the chairman and Chief Executive Officer (CEO), the president (if different from the CEO) and executive vice presidents. The compensation committee acts pursuant to a charter that has been approved by our board of directors. The charter is posted on Exelon’s website, www.exeloncorp.com, select the Investor Relations page and the Corporate Governance tab. The committee uses the services of a compensation consultant, Towers Perrin, which reports directly to the compensation committee.

The compensation committee has designed Exelon’s executive compensation program to attract and retain outstanding executives. The compensation programs are designed to motivate and reward senior management for achieving financial, operational and strategic success consistent with Exelon’s goal of being the best group of electric generation and electric and gas delivery companies in the country, thereby building value for shareholders. Exelon’s compensation program has three principles, as described below:

1. A substantial portion of compensation should be performance-based.

The compensation committee has adopted a pay-for-performance philosophy, which places an emphasis on pay-at-risk. Exelon’s compensation program is designed to reward superior performance, that is, meeting or exceeding financial and operational goals set by the compensation committee. When excellent performance is achieved, pay will increase. Failure to achieve the target goals established by the compensation committee will result in lower pay. There are pay-for-performance features in both cash and equity-based compensation. Mr. Rowe, the chairman, president and CEO,

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and the other named executive officers (NEOs) listed in the Summary Compensation Table participate in an annual incentive plan that provides cash compensation based on the achievement of performance goals established each year by the compensation committee. Mr. Rowe has an annual incentive target of 100% of his base salary, while the other NEOs have annual incentive targets of 50% to 75% of their base salaries. With respect to equity compensation, a substantial portion of each NEO’s equity-based compensation is in the form of performance share units that are paid to the extent that longer-range performance goals set by the compensation committee are met, with the balance delivered in stock options that vest on the basis of the passage of time. As a result, 85% of Mr. Rowe’s 2006 target total direct compensation (base salary plus annual and long-term incentive compensation) was at-risk. Similarly, of the other NEOs’ 2006 target total direct compensation, approximately 65% to 80% was at-risk.

2. A substantial portion of compensation should be granted as equity-based awards.

The compensation committee believes that a substantial portion of compensation should be in the form of equity-based awards in order to align the interests of the NEOs with Exelon’s shareholders. The objective is to make the NEOs think and act like owners. A significant portion of equity-based compensation is in the form of performance share units that are paid if, and only to the extent that, specific performance goals established by the compensation committee are met. The balance of their equity-based compensation is in the form of options to purchase Exelon common stock, which gain value only to the extent that the market price of Exelon’s stock increases following the grant date and the executive remains with the company for a sufficient period of time for the options to vest. As detailed below, the portion of compensation delivered in the form of equity varies among the CEO and the other NEOs.

3. Exelon’s compensation program should enable the company to compete for and retain outstanding executive talent.

Exelon’s shareholders are best served when we can successfully recruit and retain talented executives with compensation that is competitive and fair. The compensation committee strives to deliver total direct compensation at the median (the 50^th percentile), which is deemed to be the competitive level of pay of executives in comparable positions at certain peer companies with which we compete for executive talent. If Exelon’s performance is at target, the compensation will be targeted at the 50^th percentile; if Exelon’s performance is above target, the compensation will be targeted above the 50^th percentile, and if performance is below target, the compensation will be targeted below the 50^th percentile. This concept reinforces the pay-for-performance philosophy. In addition, the compensation committee compares the total direct compensation of the NEOs to each other and to other senior executives of the company to assess internal parity and considers their tenure in position and experience.

Each year the compensation committee commissions a study to benchmark total direct compensation against a peer group of companies. This analysis is conducted by a leading global compensation consulting firm, Towers Perrin, and includes an assessment of competitive compensation levels at high-performing energy services companies and other large, capital asset-intensive companies in general industry, since the company competes for executive talent with companies in both groups.

The peer group criteria include having revenue similar to Exelon’s, market capitalization generally greater than $5 billion, and a balance of industry segments. The members of the peer group are reviewed each year to determine whether their inclusion continues to be appropriate. Generally the peer group is comprised of 24 companies: 12 general industry companies and 12 energy services companies. The companies were selected by the compensation committee from the Towers Perrin Energy Services Industry Executive Compensation Database and their Executive Compensation

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Database. The general industry companies currently include: 3M, Abbott Laboratories, BellSouth Corp., Caterpillar Inc., General Mills Inc., Honeywell International, International Paper, Johnson Controls Inc., PepsiCo Inc., PPG Industries, Inc., Union Pacific Corp., and Weyerhaeuser Company. The energy services companies included American Electric Power, Centerpoint Energy, Dominion Resources, Inc., Duke Energy Corp., Edison International, Entergy Corp., FirstEnergy, PG&E Corp., Public Service Enterprise Group Incorporated, Southern Co., TXU Corp., and Xcel Energy, Inc.

In addition to this study, the compensation committee has periodically benchmarked and refined the company’s severance and change in control arrangements and perquisites programs.

Elements of Compensation

This section is an overview of our compensation program for NEOs. It describes the various elements and discusses matters relating to those items, including why the compensation committee chooses to include items in the compensation program. The next section describes how 2006 compensation was determined and awarded to the NEOs.

Exelon’s executive compensation program is comprised of four elements: base salary; annual incentives; long-term incentives; and other benefits.

Cash compensation is comprised of base salary and annual incentives. Equity compensation is delivered through long-term incentives. Together, these elements are designed to balance short-term and longer-range business objectives and to align NEOs’ financial rewards with shareholders’ interests. Approximately 30% to 55% of NEOs’ total target direct compensation is delivered in the form of cash. Equity compensation accounts for approximately 45% to 70% of NEO total target direct compensation. The range in the mix of cash and equity compensation is consistent with competitive compensation practices among companies in the peer group. The compensation committee believes that this mix of cash and equity compensation strikes the right balance of incentives to pursue specific short and long-term performance goals that drive shareholder value.

Base Salary

Base salaries for Exelon’s NEOs are determined based on individual responsibility, performance and experience, with reference to the salaries of executives in similar positions in the peer group. Generally, salaries are targeted to approximate the median (50th percentile) salary levels for comparable executives at the companies included in the peer group. The compensation committee also takes into consideration unique circumstances required to attract and retain talent. Exelon’s compensation program for NEOs is designed so that approximately 15% to 35% of NEO total direct compensation is in the form of base salary, consistent with practices at the companies in the peer group. The compensation committee reviews and recommends to the full board of directors the level of NEOs’ base salaries at its meeting in January of each year, when the results of the prior year are known. The independent directors of the Exelon board, on the recommendations of the compensation committee with input from the CEO, determine NEOs’ base salaries. In addition, Mr. Rowe has been delegated authority from the compensation committee to adjust base salaries for retention purposes or unique circumstances for officers who are not executive vice presidents or higher.

Annual Incentives

Annual incentive compensation is made available to all salaried employees, including NEOs, all non-represented hourly employees and represented employees to the extent provided in their applicable collective bargaining agreement. It is designed to provide incentives for achieving short-term financial and operational goals for the company as a whole, and for subsidiaries, individual business units and operating groups, as appropriate. Under the annual incentive program, cash awards are

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made to NEOs and other employees if, and only to the extent that, performance conditions set by the compensation committee are met. The amount of the annual incentive target opportunity is expressed as a percentage of the officer’s or employee’s base salary, and actual awards are determined using the base salary at the end of the year. In establishing targets for the annual incentive plan, the compensation committee considers several factors, including:

• The recommendations of management as to annual incentive goals that are consistent with Exelon’s business plans for the following year,

• The targets set, and achievement level in prior years, and

• The advice of Towers Perrin as to compensation practices at other companies in the peer group.

The goals under the annual incentive program are developed through an iterative process. Management, including the CEO, the CFO, other NEOs and subsidiary and business unit leadership, develop recommendations for goals that are aligned with Exelon’s business plan. Threshold, target and distinguished (i.e. maximum) achievement levels are established for each goal. Threshold is set at the minimally acceptable level of performance. Target is set consistent with the achievement of the business plan objectives. Distinguished is set at a level that significantly exceeds the business plan and has a low probability of payout.

Towers Perrin reviews the incentive practices at other companies in the peer group and makes recommendations as to appropriate levels of annual incentive compensation and structures for incentive targets that are competitive with our peer companies. The compensation committee reviews the recommendations of management and Towers Perrin for the conceptual design of the annual incentive program and establishes the final goals. In doing so, the compensation committee strives to ensure that the goals are consistent with the overall strategic goals set by the board of directors (including the individual goals of subsidiaries, as appropriate), that they are sufficiently difficult to warrant meaningful incentive payments for management, and, if the targets are met, that the payouts will be consistent with the design for the overall compensation program for the NEOs. Awards under the annual incentive program are made at the compensation committee meeting held in January, after the performance for the year has been determined. In making awards, the compensation committee has the discretion to reduce or not pay annual incentive compensation even if the targets are met. For example, 2003 annual incentive awards were reduced 30% for senior leadership, 25% for vice presidents and 20% for non-executive employees to impose some accountability for impairment of investments in Sithe and Boston Generating that adversely affected GAAP earnings. No such reduction was imposed in 2006.

The goals under the annual incentive program typically include a mixture of operating earnings per share, business unit and operating group financial measures and operating key performance indicators. The goals are weighted differently depending upon the importance of the goal to the level of the participant and his or her subsidiary or business unit. The weighting also reflects the compensation committee’s view as to the appropriate balance of central corporate goals, such as operating earnings, and business unit and operating group financial measures and operating key performance indicators. Operating earnings may be adjusted for non-operating charges and other one-time, unusual and non-recurring items that are not indicative of the company’s ongoing performance. The compensation committee approves all adjustments. Generally, the items excluded from adjusted operating earnings for compensation purposes are the same as the items excluded from adjusted (non-GAAP) operating earnings that the company reports to investors in its quarterly earnings releases, although the compensation committee sometimes exercises discretion to include items for compensation purposes that are excluded for reporting purposes in the earnings releases. For information concerning the goals applicable to the 2006 annual incentives, please see the table within the other NEOs’ 2006 Annual Incentives section below.

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Actual incentive payments can vary from 0 (if the threshold is not uniformly met) to 50% of target (if the threshold is met), 100% of target (if the target is met or exceeded), and capped at 200% of target (the maximum possible payment if performance is uniformly “distinguished”), but with respect to NEOs, also cannot exceed the amount available to each NEO under an incentive pool established by the compensation committee to fund NEO awards. Awards are interpolated to the extent performance falls between the threshold, target, and distinguished levels. In addition, the compensation committee has the discretion to apply an individual performance multiplier that can be used to adjust awards from minus 50% to plus 10%, subject to the maximum 200% of the target opportunity and the amounts available under the incentive pool.

Long-term Incentives

As noted above, the compensation committee believes that a substantial portion of long-term compensation also should be performance-based, using goals established by the compensation committee. Long-term incentives are made available to executives and key management employees who affect the long-term success of the company. The long-term incentives are designed to provide incentives and rewards closely related to the interests of Exelon’s shareholders, as measured by the performance of Exelon’s total shareholder return and stock price appreciation. To further align the interests of the recipients of long-term incentive compensation, including the NEOs, with our shareholders, our long-term incentive compensation programs are equity-based. The compensation committee has adopted additional policies based on its desire to align the interests of NEOs and other officers with the interests of our shareholders, such as our guidelines for stock ownership and restrictions on stock sales, as described below.

Long-term incentives for Exelon’s executives are generally based on a combination of non-qualified options to purchase Exelon common stock and performance share units awarded under the company’s shareholder-approved long-term incentive plan. The compensation committee grants a portion of the long-term incentive compensation in the form of performance share units that are awarded only if, and to the extent that, performance conditions established by the compensation committee are met. The balance of long-term incentive compensation is in the form of time-vested stock options. The use of both forms of long-term incentives is consistent with the practices in our peer group, as reported by Towers Perrin. The stock options provide value only if, and to the extent that, the market price of Exelon’s common stock increases following the grant. In this way, stock options align the interests of the option holders with our shareholders, so that option holders only gain if our shareholders gain. The mix of long-term incentives varies from year to year. The mix depends on the compensation committee’s assessment of the appropriate balance between cash and equity-based incentive compensation and short and long-term incentives, as well as the competitive compensation practices of companies in the peer group identified by Towers Perrin in its report to the compensation committee. In 2005, the mix of long-term incentive value was 50% stock options and 50% performance shares. In 2006, the compensation committee determined that the value mix should be changed to 35% stock options and 65% performance shares based on trends in long-term incentive compensation practices that Towers Perrin reported to the compensation committee. This trend is due in part to the effect of the implementation of SFAS No. 123-R on the accounting for equity-based compensation.

Stock Options

A portion of the long-term incentive opportunity is delivered in the form of stock options to align management and shareholder interests, support a long-term perspective and planning process and attract, motivate and retain executive talent. Stock options correlate well with shareholder interests because they gain value only to the extent that the stock price increases above the exercise 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. The target for the number of options awarded is determined by the portion of the long-term incentive value attributable to stock options and

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a theoretical value of each option determined by the compensation committee using a Black-Scholes valuation formula. Options vest in equal annual installments over a four-year period and have a term of ten years. Time vesting adds a retention element to our stock option program. Stock option repricing is prohibited by policy or terms of the company’s long-term incentive plans. Accordingly, no options have been repriced. Stock option awards are generally granted at the regularly scheduled January compensation committee meeting when the committee reviews results for the preceding year and establishes the compensation program for the coming year. The compensation committee has delegated to the CEO the authority to make off-cycle awards to an employee who is not subject to the limitations of Section 162(m), is not an executive officer for purposes of reporting under Section 16 of the Securities Exchange Act of 1934, and is not an executive vice president or higher of Exelon, provided that such authority is limited to making grants of up to 1,200,000 options in the aggregate and 20,000 options per recipient in any year. These grants are ratified by the compensation committee. On rare occasions, stock options are granted to new hires on the date they commence employment. This delegated authority was used to make seven grants in 2006, none of which were to NEOs. All grants to the NEOs must be approved by the full board of directors, which acts after receiving a recommendation from the compensation committee, except grants to Mr. Rowe, which must be approved by the independent directors, who act after receiving recommendation from the compensation committee.

Performance Share Units

The compensation committee established a performance share unit award program contingent on performance as measured against predetermined objectives over a multi-year measurement period with the value fluctuating with stock price changes as well as performance against objectives. At the beginning of each year, the compensation committee and the board of directors establish targets for performance share unit awards for each executive. The performance goals are based on total shareholder return for Exelon as compared to the companies in the Standard & Poor’s 500 Index and the Dow Jones Utility Index for the three-year period ending on December 31 of that year and may include other measures. For information concerning the goals applicable to the 2006 long-term performance share unit awards, please see the Long-term Incentives section below. Actual awards are determined at the January meeting of the compensation committee and the board of directors after the end of the performance period when the extent of achievement of the performance goals is known. One third of the awarded performance shares vests upon the award date with the balance vesting in January of the next two years. The vesting schedule is designed to add a retention factor to the program. The form of payment provides for payment in Exelon common stock to executives with lower levels of stock ownership, with increasing portions of the payments being made in cash as executives’ stock ownership levels increase in excess of the ownership guidelines. This payment structure serves to deliver the long-term compensation in cash where the executive has substantially greater than the required stock ownership and provides the executive with liquidity and the opportunity for diversification.

Restricted Stock & Restricted Stock Units

In limited cases, the compensation committee has determined that it is necessary to grant restricted shares of Exelon common stock or restricted stock units to executives as a means to recruit and retain talent. They may be used for new hires to offset annual or long-term incentives that are forfeited from a previous employer. They are also used as a retention vehicle and are subject to forfeiture if the executive voluntarily terminates.

Executive stock ownership and trading 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 promotion to their current position. For additional information about Exelon’s stock ownership guidelines, please see the Stock Ownership Guidelines section in Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

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Exelon has adopted a policy requiring officers, executive vice presidents and above, who wish to sell Exelon common stock to do so only through Rule 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 retirement and tax planning activities. The use of Section 10b5-1 stock trading plans serves to reduce the risk that investors will view routine portfolio diversification stock sales by executive officers as a signal of negative expectations with respect to the future value of Exelon’s stock. In addition, the use of Rule 10b5-1 stock trading plans reduces the potential for accusations of trading on the basis of material, non-public information that could damage the reputation of the company. All of the NEOs have such plans, and their exercises during 2006 are reflected in the “Option Exercises and Stock Vested” table below. Because Mr. Rowe retains a portion of the shares obtained upon the exercise of stock options, the number of shares he owns increases through his stock trading plan. Exelon’s stock trading policy does not permit short sales or hedging.

Other Benefits

Other benefits offered by Exelon include such things as qualified and non-qualified deferred compensation programs, post-termination compensation, retirement benefit plans and perquisites. The company also provides other benefits such as medical and dental coverage and life insurance to each NEO to generally the same extent as such benefits are provided to other Exelon employees, except that executives pay a higher percentage of their total medical premium. These benefits are intended to make our executives more efficient and effective and provide for their health, well-being and retirement planning needs. The compensation committee reviews these other benefits to confirm that they are reasonable and competitive in light of the overall goal of designing the compensation program to attract and retain talent while maximizing the interests of our shareholders.

Deferred Compensation Programs

Exelon offers deferred compensation plans to permit the deferral of certain cash compensation and equity awards to facilitate tax and retirement planning and satisfaction of stock ownership requirements for executives and certain key managers. Exelon maintains non-qualified deferred compensation plans that are open to certain highly-compensated employees, including the NEOs.

The Deferred Compensation Plan is a non-qualified plan that permits executives and key managers to defer base salary, annual incentive, and contributions that would be made to the Exelon Corporation Employee Savings Plan (the company’s tax-qualified 401(k) plan) but for the applicable limits under the Internal Revenue Code. The Deferred Compensation Plan permits participants to defer taxation of a portion of their income. It benefits the company by deferring the payment of a portion of its compensation expense, thus preserving cash.

The Employee Savings Plan is tax-qualified under Sections 401(a) and 401(k) of the Internal Revenue Code. Exelon maintains the Employee Savings Plan to attract and retain qualified employees, including the NEOs, and to encourage employees to save some percentage of their cash compensation for their eventual retirement. The Employee Savings Plan permits employees to do so, and allows the company to contribute, in a relatively tax-efficient manner. The amount of compensation that can be taken into account under a tax-qualified plan is limited under the Internal Revenue Code, which also limits amounts that can be deferred in any year. Subject to the applicable Internal Revenue Code limitations, participating management employees may contribute up to a total of 50% of base salary each year on a pre-tax, Roth or after-tax basis (or any combination thereof). In addition, the company will match the contributions dollar for dollar up to the first 5% of base salary deferred each pay period. The Deferred Compensation Plan (described above) includes a feature that provides for

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the deferral and payment, out of general assets, of an amount substantially equal to the difference between the amount that, in the absence of the Internal Revenue Code limitations, would have been allocated to an employee’s Employee Savings Plan account as pre-tax contributions plus matching contributions, and the amount actually allocated under the Employee Savings Plan. The company maintains the excess matching feature of the Deferred Compensation Plan to enable management employees to save for their eventual retirement to the extent they otherwise would have were it not for the limits established by the IRS for purposes of Federal tax policy.

The Stock Deferral Plan permits executives to defer the receipt of shares awarded under the company’s performance share unit award program. Performance shares paid in cash cannot be deferred.

In response to declining plan enrollment and the administrative complexity of compliance with Section 409A of the Internal Revenue Code, the compensation committee approved amendments to the Deferred Compensation and Stock Deferral Plans at its December 4, 2006 meeting. For more information about the amendments, please see ITEM 15. Exhibits and Financial Statement Schedules.

Change In Control and Severance Benefits

The compensation committee believes that change in control employment agreements and severance benefits are an important part of Exelon’s compensation structure for NEOs. The compensation committee believes that these agreements will help to secure the continued employment and dedication of the NEOs, notwithstanding any concern they might have at such time regarding their own continued employment, prior to or following a change in control. The compensation committee also believes that these agreements and the Exelon Corporation Senior Management Severance Plan are important as recruitment and retention devices, as all or nearly all of the companies with which Exelon competes for executive talent have similar protections in place for their senior leadership.

Under the terms of his employment agreement, Mr. Rowe has benefits similar to those provided under the change in control employment agreements and the Exelon Corporation Senior Management Severance Plan. Additional information regarding the change in control employment agreements, the change in control and severance terms of Mr. Rowe’s employment agreement, and the Exelon Corporation Senior Management Severance Plan, including definitions of key terms and a quantification of benefits that would have been received by our NEOs had termination occurred on December 31, 2006, is found in the “Potential Payments upon Termination or Change-in-Control” section below.

Retirement Benefit Plans

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 represented employees. Effective January 1, 2001, Exelon also established two cash balance defined benefit pension plans to both reduce future retirement benefit cost and provide an option that is portable as the company anticipated a work force that was more mobile than the traditional utility workforce. The cash balance defined benefit pension plans cover management employees and certain represented employees hired on or after such date, as well as management employees hired prior to such date who elected to transfer from their traditional pension plan to the cash balance plan.

The amount of compensation that can be taken into account under the tax-qualified retirement plans is limited under the Internal Revenue Code and was $220,000 for 2006. As permitted by the Employee Retirement Income Security Act of 1974, as amended (ERISA), Exelon also sponsors

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non-qualified supplemental pension plans (the SERP) that allow the payment, out of general assets, to certain highly-compensated individuals of any benefits calculated under the applicable tax-qualified plan benefit formula that exceed these limits. Exelon maintains the SERP to restore benefits to the level they otherwise would have been were it not for the limits established by the IRS for purposes of Federal tax policy.

For purposes of the SERP, Mr. Skolds received an additional 7 ¹/2 years of credited service upon his 5^th anniversary of employment and will receive an additional 7 ¹/2 years upon his 10^th anniversary in 2010. These credited years of service were awarded to him when he came to work for Exelon in 2000 to compensate Mr. Skolds for the pension benefits from his former employer that he surrendered to come to work for the company. Mr. Mehrberg received an additional 10 years of credited service for purposes of the SERP upon his fifth anniversary. He was awarded these credited years of service in 2002 as a retention incentive. Mr. Crane received an additional eight years of credited service for purposes of the SERP through December 31, 2006 as part of his employment offer that provides one additional year of service credit for each year of employment to a maximum of 10 additional years.

Under his employment agreement, Mr. Rowe is entitled to receive a special supplemental executive retirement plan benefit (the SERP benefit) upon termination of employment for any reason other than for cause. The SERP benefit was negotiated with Mr. Rowe in 1998 as part of his initial employment agreement to attract him from a previous employer, where he also served as CEO. The 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 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.

As of January 1, 2004, Exelon ceased the practice of granting 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 available under employment, change in control or severance agreements or arrangements (or any successor arrangements) in effect as of January 1, 2004 are not affected by this policy. To attract a new executive, Exelon is permitted to grant additional years of service under the SERP related to its cash balance pension plan to make the executive whole for retirement benefits lost from another employer by joining Exelon, provided such a grant is disclosed to shareholders. To date, Exelon has not made any such grant.

The compensation committee believes that the pension plans and the SERP are an important part of the NEO compensation program. These plans serve a critically important role in the retention of senior executives, as benefits thereunder increase for each year that these executives remain employed. The plans thereby encourage our most senior executives to remain employed and continue their work on behalf of the shareholders.

Perquisites

Exelon provides limited perquisites intended to serve specific business needs for the benefit of Exelon; however, it is understood that some may be used for personal reasons as well. When perquisites are utilized for personal reasons, the cost or value 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 in which case the company may reimburse the officer for the taxes due on the imputed income. The Summary Compensation Table and related footnotes below detail the perquisites provided and summarize their incremental cost to the company. In 2005, Towers Perrin reviewed Exelon’s perquisites program. Although specific data for Exelon’s peer group was not available, Towers Perrin based its analysis on survey data for large energy and general industry

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companies. Towers Perrin found that Exelon’s perquisite program was competitive. The compensation committee reviewed the costs of the perquisite program and determined the costs to be appropriate for a company of Exelon’s size.

At its January 22, 2007 meeting, the compensation committee approved the phase-out of most executive perquisites, effective January 1, 2008. The eliminated perquisites will include: leased vehicles (existing leases allowed to expire), financial and estate planning, tax preparation and health and dining/airline club memberships. The phase-out approach includes a one-time transition payment in January 2008. The CEO will not receive a transition payment. Exelon will continue to provide executive physicals, parking in downtown Chicago, supplemental long term disability insurance and executive life insurance for those with existing policies. Exelon will continue to provide Mr. Rowe with 50 hours of personal travel per year on the corporate aircraft and executive chauffeur services because of the time commitments his position requires.

How The Amount of 2006 Compensation Was Determined

This section describes how 2006 compensation was determined and awarded to the NEOs.

CEO compensation

Exelon’s CEO participates in the same programs and receives compensation based on the same factors as the other NEOs. 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 Exelon. 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 2006. 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 Exelon board considered the financial highlights of the year and a strategy scorecard that assessed performance against the company’s vision and goals. The factors considered included goals with respect to protecting the current value of the company, including delivering superior operating performance in terms of safety, reliability, customer satisfaction and efficiency, supporting competitive markets, protecting the value of our generation assets, and building healthy, self-sustaining delivery companies. The factors considered also included four goals relating to growing long-term value, including organizational improvement, aligning financial management policies with the changing profile of the company, rigorously evaluating new growth opportunities, and advancing an environmental strategy that leverages Exelon’s carbon position. The Exelon board considered, in particular, strong results in operating earnings, Exelon’s leading market capitalization, and successful nuclear and fossil operations, as well as the successful implementation of a new billing system at PECO and improvements in communications and external relations. It also considered areas where results were less than hoped for, such as the failure to obtain acceptable merger approvals, the regulatory difficulties in Illinois, and the need to continue improving delivery reliability.

How base salary was determined

Base salaries for the executives were determined based on individual performance and experience, with reference to the salaries of executives in similar positions in the peer group.

Mr. Rowe’s 2006 Base Salary. The independent directors of the Exelon board, on the recommendations of the compensation committee and the corporate governance committee, determined Mr. Rowe’s base salary for serving as the CEO by considering:

• a review of benchmark levels of base pay, which were provided by the compensation committee’s consultant;

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• Mr. Rowe’s length of service as CEO at Exelon and other companies in the industry;

• performance achieved against financial and operational goals; and

• the performance assessment discussed above.

Mr. Rowe’s annualized base salary was increased by 4% to $1,300,000 effective March 1, 2006.

Other Named Executives’ 2006 Base Salaries. At its January 23, 2006 meeting, the compensation committee reviewed base salary data for the other NEOs listed in the Summary Compensation Table as compared to compensation data at the 50^th and 75^th percentile of the proposed peer group for the then-planned merger of Exelon and PSEG. However, in light of the delay in closing the proposed merger, the compensation committee recommended that base salaries for several of the named executive officers be increased modestly in 2006, with a further review of base salaries to be conducted after the closing of the merger to determine whether more substantial increases would be appropriate in light of increased responsibilities for the NEOs. Accordingly, the following NEOs received base salary increases during 2006:

Exelon, Generation and PECO

Name	Base Salary		Percent Increase		Effective Date
Skolds	$	635,000	4.1	%	3/1/2006
Young		550,000	3.8	%	3/1/2006
Mehrberg		560,000	3.7	%	3/1/2006
McLean		445,000	3.5	%	3/1/2006
Crane		510,000	5.2	%	3/1/2006
O’Brien		400,000	6.7	%	3/1/2006
ComEd Name	Base Salary		Percent Increase		Effective Date
Costello	$	375,000	11.9	%	8/1/2006

Due to the termination of the Merger, no further base salary increases occurred for NEOs in 2006. Messrs. Clark, McDonald, Mitchell and Hilzinger received pay increases in late 2005 and did not receive base salary increases in 2006.

How 2006 annual incentives were determined

For 2006, the annual incentive payments to Mr. Rowe and each of nine other senior executives were funded by a notional incentive pool established by the Exelon compensation committee under the Annual Incentive Plan for Senior Executives, a shareholder-approved plan, which is intended to comply with Section 162(m). The incentive pool was funded with 1.5% of Exelon’s operating income, the same percentage used in 2005, but was not fully distributed to participants because the committee decided on substantially lesser awards.

Annual incentive payments for 2006 to Messrs. Rowe, Skolds, Young and Mehrberg were made from the portion of the incentive pool available to fund awards for each of them based on the company’s operating earnings per share, adjusted for non-operating charges and other one-time, unusual and non-recurring items. The compensation committee reviewed 2006 earnings and decided not to include the effects of certain items in adjusting earnings for purposes of making awards under the annual incentive plan, such as, certain changes in GAAP, mark-to-market adjustments, investments in synthetic-

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fuel producing facilities, significant impairments of intangible assets, certain losses on sales of businesses, AmerGen nuclear decommissioning obligation, impacts of certain regulatory recoveries and certain costs associated with the terminated merger with PSEG. 2006 annual incentive payments for other NEOs were based upon a combination of adjusted operating earnings per share and other company and business unit financial and operating measures. For executives with general corporate responsibilities, the goal was adjusted operating earnings per share so that they would focus their efforts on overall corporate performance. For executives with specific business unit responsibilities, the goals were a mix of earnings per share (so that they would focus on overall corporate performance) and business unit financial and/or operating measures, depending on the nature of their responsibilities. The following table summarizes the goals and weights applicable to the NEOs.

Exelon, Generation and PECO

Name	Adjusted Operating Earnings Per Share*1		Generation Operating Net Income*2		Exelon Energy Delivery (EED) Financial Measures*3		EED Operational Measures*4		Composite of All EED & Generation Goals*5		Business Services Company Expense vs. Budget*6		ComEd Financial Measures*7
Rowe	100	%
Skolds	100	%
Young	100	%
Mehrberg	100	%
Clark	20	%					40	%					40	%
McLean	50	%	50	%
Crane	50	%	50	%
O’Brien	25	%			25	%	50	%
Hilzinger	25	%							30	%	45	%

ComEd

Name	Adjusted Operating Earnings Per Share*1		ComEd Financial Measures*7		EED Operational Measures*4		Composite of All EED & Generation Goals*5		Business Services Company Expense vs. Budget*6
Clark	20	%	40	%	40	%
McDonald	20	%	40	%	40	%
Mitchell	20	%	40	%	40	%
Costello	20	%	40	%	40	%
Hilzinger	25	%					30	%	45	%

Footnotes

*1 The adjusted operating earnings per share threshold, for a 50% payout, was $2.75; the target, for a 100% payout, was $3.15; distinguished, for a 200% payout, was $3.45.

*2 The Generation Operating Net Income (in $ millions) threshold, for a 50% payout, was $1,001; the target, for a 100% payout, was $1,170; distinguished, for a 200% payout, was $1,271.

*3 The EED Financial Measures are comprised of EED Total Cost (O&M and Capital) and EED Net Income. For the EED Total Cost goal (as a % of budget), the threshold for a 50% payout, was 103%; the target, for a 100% payout, was 100%; distinguished, for a 200% payout, was 98%. For the EED Net Income goal, the threshold (in $ millions), for a 50% payout, was $920; the target, for a 100% payout, was $1,004; distinguished, for a 200% payout, was $1,070.

*4 EED Operational Measures are comprised of EED Customer Average Interruption Duration Index (CAIDI), EED System Average Interruption Frequency Index (SAIFI) and EED OSHA Recordable Rate. For the EED CAIDI goal, the threshold (in minutes), for a 50% payout, was 120; the target, for a 100% payout, was 99; distinguished, for a 200% payout, was 90. For the EED SAIFI goal, the threshold (expressed as total number of customer interruptions divided by the total number of customers served), for a 50% payout, was 1.24; the target, for a 100% payout, was 1.08; distinguished, for a 200% payout, was 1.00. For the EED OSHA Recordable Rate goal (calculated as recordable x 200,000 divided by exposure hours), the threshold, for a 50% payout, was 2.66; the target, for a 100% payout, was 1.68; distinguished, for a 200% payout, was 1.51.

*5 The Composite of All EED & Generation goals is comprised of EED Net income, EED Total Cost, EED CAIDI, EED SAIFI, EED OSHA Recordable Rate, Generation Operating Net Income, Nuclear Total Net Operating Expenses, Nuclear Fleet-Wide Capacity Factor, Power Net Operating Expense, Commercial Availability-Fossil Fleet, Equivalent Availability-Hydro, and Power Team Operating Margin.

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*6 The BSC Expense vs. Budget goal is comprised of the BSC Operating Expense vs. Budget goal and Finance Group Operating Expense vs. Budget goal. Both goals are expressed as a percent of budget and the threshold for a 50% payout, was 105%; the target, for a 100% payout, was 100%; distinguished, for a 200% payout, was 97%.

*7 The ComEd Financial Measures are comprised of ComEd Total Cost (operating and maintenance expense and capital) and ComEd Net Income. For the ComEd Total Cost goal (as a % of budget), the threshold for a 50% payout, was 103%; the target, for a 100% payout, was 100%; distinguished, for a 200% payout, was 98%. For the ComEd Net Income goal, the threshold (in $ millions), for a 50% payout, was $465; the target, for a 100% payout, was $536; distinguished, for a 200% payout, was $590.

Annual incentive payments were also based on customer satisfaction as measured by performance on the American Customer Satisfaction Index (ACSI) Proxy objective, and individual performance.

The ACSI Proxy captures the overall opinions from customers in all segments—residential, large commercial and industrial and small commercial and industrial. If the ACSI Proxy fell below the 3rd Quartile of peer group utilities, AIP awards would have been reduced by 2.5%. If the ACSI Proxy rose from the 3rd Quartile to the 2nd Quartile, the AIP Awards would have been increased by 5%. An independent research firm tabulates the ACSI Proxy score after asking customers to rate their utility using three survey measures: How satisfied customers are with the company overall; the extent to which the company falls short or exceeds customers’ expectations; and how close the company is to their ideal energy utility company.

For the evaluation period of Q1 2006 through Q3 2006, the company achieved a score of 70.7, which was in the 2nd quartile. As a result of meeting the 2006 customer satisfaction objective of the Annual Incentive Program (AIP), all annual incentive payments were increased by 5%.

Mr. Rowe’s 2006 Annual Incentive. Taking into account the performance review discussed above, the compensation committee and the corporate governance committee recommended, and the independent directors of the Exelon board approved, an award of $1,851,800 for Mr. Rowe, which is 129.5% of his target annual incentive opportunity and in addition the effect of an individual performance multiplier (IPM) of 110%. The individual performance multiplier is used at the discretion of the compensation committee to adjust awards from minus 50% to plus 10% subject to the maximum 200% of target opportunity and the amount available to fund his award under the incentive pool.

Other Named Executive Officers’ 2006 Annual Incentives. The compensation committee recommended and the board of directors approved the following awards for the other NEOs:

Exelon, Generation and PECO

Name	% of Target Opportunity (Pre IPM)		IPM		Award
Skolds	129.5	%	100	%	$	616,744
Young	129.5	%	100	%		498,575
Mehrberg	129.5	%	100	%		507,640
Clark	114.2	%	100	%		326,584
McLean	143.5	%	100	%		383,145
Crane	143.5	%	110	%		483,021
O’Brien	86.6	%	110	%		228,654
Hilzinger	137.7	%	105	%		227,757

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ComEd

Name	% of Target Opportunity (Pre IPM)		IPM		Award
Clark	114.2	%	100	%	$	326,584
McDonald	114.2	%	105	%		179,850
Mitchell	114.2	%	105	%		298,551
Costello	114.2	%	100	%		214,107
Hilzinger	137.7	%	105	%		227,757

With respect to the NEOs in the above tables, individual performance multipliers above 100% were approved and recommended by the compensation committee based upon favorable assessments of their performance and input from the CEO. Under the terms of the Annual Incentive Program, the individual performance multiplier is used to adjust awards from minus 50% to plus 10% subject to the maximum 200% of target opportunity and the amounts available under the incentive pool. Awards under the annual incentive plan are shown in the Summary Compensation Table below under the column headed “Non-Equity Incentive Plan Compensation” to the extent attributable to the extent of meeting the performance measures, and in the column headed “Bonus” to the extent attributable to the individual performance multipliers.

Long-term incentives

For 2006, the compensation committee changed the mix of long-term incentive awards from 50% stock options and 50% performance share awards to 35% stock options and 65% performance share awards, based on the results of the Towers Perrin study and emerging long-term incentive trends among Exelon’s peer companies.

Stock option awards

Exelon granted non-qualified stock options to key management employees, including the NEOs except Mr. Rowe, on January 23, 2006. These options were awarded at an exercise price of $58.55, which was the closing price on the January 23, 2006 grant date. At Mr. Rowe’s request, the compensation committee determined that he would not receive stock options for 2006. This was not offset with any other form of compensation.

Exelon performance share unit awards

The 2006 Long-Term Performance Share Unit Award Program was based on two measures, Exelon’s three-year Total Shareholder Return (TSR), compounded monthly, as compared to the TSR for the companies listed in the Dow Jones Utility Index (60% of the award), and Exelon’s three-year TSR, as compared to the companies in the Standard and Poor’s 500 Index (40% of the award). As a result of the planned merger with PSEG, the compensation committee decided to eliminate The Exelon Way cash savings goal that was a component of the 2005 performance share award program.

Payouts are determined based on the following scale: The threshold TSR Position Ranking, for a 50% of target payout, was the 25^th percentile; the target, for a 100% payout, was 50^th percentile; and distinguished, for a 200% payout, was the 75^th percentile, with payouts interpolated for performance falling between the threshold, target, and distinguished levels.

Exelon exceeded target performance levels with respect to both TSR measures. For the performance period of January 1, 2004 through December 31, 2006, Exelon’s relative ranking of TSR as compared to the Dow Jones Utility Index was between the target and the distinguished level (68.7 percentile ranking or 174.8% of target payout). For the same time period, the company’s relative

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ranking of TSR in the S&P 500 Index was at the distinguished level (86 percentile ranking or 200.0% of target payout). Overall performance against both measures combined resulted in a payout to participants for 2006 that represented 184.9% of each participant’s target opportunity.

Based on the formula, 2006 Performance Share Unit Awards for NEOs were as follows:

Exelon, Generation and PECO

Name	Shares	Value*		Form of Payment**
Rowe	127,581	$	7,649,757	100% Cash
Skolds	36,980		2,217,321	100% Cash
Young	30,509		1,829,290	50%Cash/50% Stock
Mehrberg	30,509		1,829,290	100% Cash
Clark	24,037		1,441,259	100% Cash
McLean	30,509		1,829,290	100% Cash
Crane	24,037		1,441,259	50%Cash/50% Stock
O’Brien	16,641		997,794	50%Cash/50% Stock
Hilzinger	9,245		554,330	50%Cash/50% Stock

ComEd

Name	Shares	Value*		Form of Payment**
Clark	24,037	$	1,441,259	100% Cash
McDonald	9,245		554,330	50%Cash/50% Stock
Mitchell	16,641		997,794	50%Cash/50% Stock
Costello	9,245		554,330	50%Cash/50% Stock
Hilzinger	9,245		554,330	50%Cash/50% Stock

* Based on the closing stock price of $59.96 on January 22, 2007.

** Form of payment based on stock ownership level. Stock payment means amounts paid in shares of Exelon common stock. Refer to the Stock Ownership Guidelines section in Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The figures in this column are not the same as the figures reported in column E of the Summary Compensation Tables because of the effect of the vesting requirement.

Tax and Accounting Consequences

Under Section 162(m) of the Internal Revenue Code, executive compensation in excess of $1 million paid to a CEO 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) and applicable regulations, remains deductible. The compensation committee intends to continue reliance on performance-based compensation programs, consistent with sound executive compensation policy. The compensation 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.

Because it is not “qualified performance-based compensation” within the meaning of Section 162(m), base salary is not eligible for a Federal income tax deduction to the extent that it exceeds $1 million. Accordingly, Exelon is unable to deduct that portion of Mr. Rowe’s base salary in excess of $1 million. Annual incentive payments to NEOs and performance share units are intended to be qualified performance-based compensation under Section 162(m), and are therefore deductible for Federal income tax purposes. Restricted stock and restricted stock units are not deductible by the company for Federal income tax purposes under the provisions of Section 162(m) if NEO compensation is in excess of $1 million.

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As noted above, the Deferred Compensation Plan and the Stock Deferral Plan were amended in December 2006 in part to address the administrative complexity of compliance with Section 409A of the Internal Revenue Code.

Also as noted above, the value mix of long-term incentive compensation was changed in 2006 from 50% stock options and 50% performance share units to 35% stock options and 65% performance share units in part because of the effect of the implementation of SFAS No. 123-R on the accounting for equity-based compensation.

Conclusion

The compensation committee is confident that Exelon’s compensation programs are performance-based and consistent with sound executive compensation policy. They are designed to attract, retain and reward outstanding executives and to motivate and reward senior management for achieving high levels of business performance, customer satisfaction and outstanding financial results that build shareholder value.

COMPENSATION COMMITTEE REPORT

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in the 2006 Annual Report on Form 10-K and the 2007 Proxy Statement.

The Compensation Committee

Edward A. Brennan, Chair

M. Walter D’Alessio

Rosemarie B. Greco

Ronald Rubin

Richard L. Thomas

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Stock Performance Graph

The performance graph below illustrates a five year comparison of cumulative total returns based on an initial investment of $100 in Exelon Corporation common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index for the period 2001 through 2006.

This performance chart assumes:

• $100 invested on December 31, 2001 in Exelon Corporation common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and

• All dividends are reinvested.

	2001		2002		2003		2004		2005		2006
Exelon Corporation	$	100.00	$	114.04	$	148.09	$	203.40	$	253.08	$	302.99
S&P 500		100.00		77.95		100.27		111.15		116.59		134.96
S&P Utilities		100.00		70.06		88.27		109.58		127.89		154.70

Summary Compensation Table

The tables below summarize the total compensation paid or earned by each of the named executive officers of Exelon, Generation, PECO (shown in one table because of the overlap in their named executive officers) and ComEd for the year ended December 31, 2006.

Salary amounts may not match the amounts discussed in Compensation Discussion and Analysis because that discussion concerns salary rates; the amounts reported in the Summary Compensation Tables reflect actual amounts paid during the year including the effect of changes in salary rates. Changes to base salary generally take effect on March 1, and there may also be changes at other times during the year to reflect promotions or changes in responsibilities.

Bonus reflects amounts paid under the annual incentive plan on the basis of the individual performance multiplier approved by the compensation committee and the board of directors or, in the case of Mr. Rowe, approved by the independent directors.

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Stock awards include awards of performance share units. All performance share units are made pursuant to the terms of the 2006 Long-Term Incentive Plan based upon the achievement of goals, as described above. One-third of the award vests upon the award date with the balance vesting ratably over the next two years. Upon retirement or involuntary termination not for cause, earned but non-vested shares are eligible for accelerated vesting. The form of payment provides for payment in Exelon common stock to executives with lower levels of ownership, with increasing portions of the payments being made in cash as executives’ stock ownership levels increase in excess of the ownership guidelines. If an executive achieves 125% or more of the applicable ownership target, performance shares will be paid half in cash and half in stock. If executives, EVP and above, achieve 200% or more of the applicable ownership target, their performance shares will be paid entirely in cash. Stock awards also include restricted stock or stock unit awards. When awarded, restricted stock or stock units are earned by continuing employment for a pre-determined period of time or, in some instances, after certain performance requirements are met. In some cases, the award may vest ratably over a period; in other cases, it vests as a whole at one or more pre-determined dates. Among the NEOs for Exelon, Generation and PECO, Messrs. Skolds, Young, Clark, Crane, O’Brien and Hilzinger have received awards of restricted stock or restricted stock units in the past. Among the NEOs for ComEd, Messrs. Clark, McDonald, Mitchell, Costello and Hilzinger have received awards of restricted stock or restricted stock units in the past. Of the NEOs, only Mr. O’Brien received a restricted stock award in 2006.

All option awards are made pursuant to the terms of the 2006 Long-Term Incentive Plan and are for the purchase of Exelon common stock. All options are granted at a strike price that is not less than the fair market value of a share of stock on the date of grant. Fair market value is defined under the plans as the closing price on the grant date as reported on the New York Stock Exchange. Options vest in equal annual installments over a four-year period and have a term of ten years. Employees who are retirement eligible are eligible for accelerated vesting upon retirement or termination.

Non-equity incentive plan compensation includes the amounts earned under the annual incentive plan by the extent to which the applicable financial and operational goals were achieved. The annual incentive plan for 2006 is described in Compensation Discussion and Analysis above.

Exelon, Generation and PECO

Name and Principal Position	Year	Salary ($)		Bonus ($) See Note 14		Stock Awards ($) See Note 15		Option Awards ($) See Note 16		Non-Equity Incentive Plan Compensa- tion ($) See Note 17		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($) See Note 18		All Other Compen- sation ($) See Note 19		Total ($)
(A)	(B)	(C)		(D)		(E)		(F)		(G)		(H)		(I)		(J)
Rowe(1)	2006	$	1,291,918	$	168,345	$	10,527,089	$	1,324,393	$	1,683,455	$	856,413	$	575,455	$	16,427,068
Skolds(2)	2006		630,959		—		3,012,980		863,280		616,744		381,656		165,376		5,670,995
Young(3)	2006		546,767		—		2,174,945		310,360		498,575		77,622		158,808		3,767,077
Mehrberg(4)	2006		556,767		—		2,917,114		746,480		507,640		263,587		144,995		5,136,583
Clark(5)	2006		440,000		—		2,239,794		592,755		326,584		158,233		162,925		3,920,291
McLean(6)	2006		442,575		—		1,811,526		407,167		383,145		62,625		102,602		3,209,640
Crane(7)	2006		505,959		43,911		1,545,742		309,035		439,110		352,298		131,404		3,327,459
O’Brien(8)	2006		395,959		20,786		1,063,147		201,293		207,868		118,966		91,324		2,099,343
Hilzinger(9)	2006		315,000		10,846		587,369		101,873		216,911		42,776		58,411		1,333,186

1. John W. Rowe, Chairman, President & CEO, Exelon. Mr. Rowe is an executive officer of Exelon, Generation and PECO.

2. John L. Skolds, Executive Vice President, Exelon; President, Exelon Energy Delivery and Exelon Generation. Mr. Skolds is an executive officer of Exelon, Generation and PECO.

3. John F. Young, Executive Vice President, Finance & Markets and CFO, Exelon, Generation and PECO.

4. Randall E. Mehrberg, Executive Vice President, Chief Administrative Officer & Chief Legal Officer, Exelon.

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5. Frank M. Clark, Chairman and CEO, ComEd. Mr. Clark is shown as an executive officer of Exelon solely by reason of his position as Chairman and CEO of ComEd.

6. Ian P. McLean, Executive Vice President, Exelon; President, Exelon Power Team. Mr. McLean is an executive officer of Exelon and Generation.

7. Christopher M. Crane, Senior Vice President, Exelon; President and Chief Nuclear Officer, Exelon Nuclear. Mr. Crane is an executive officer of Generation.

8. Denis P. O’Brien, President, PECO.

9. Matthew F. Hilzinger, Senior Vice President and Controller, Exelon, Chief Accounting Officer, PECO.

ComEd

Name and Principal Position (A)	Year (B)	Salary ($) (C)		Bonus ($) See Note 14 (D)		Stock Awards ($) See Note 15 (E)		Option Awards ($) See Note 16 (F)		Non-Equity Incentive Plan Compensa -tion ($) See Note 17 (G)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($) See Note 18 (H)		All Other Compen- sation ($) See Note 19 (I)		Total ($) (J)
Clark(5)	2006	$	440,000	$	—	$	2,239,794	$	592,755	$	326,584	$	158,233	$	162,925	$	3,920,291
McDonald(10)	2006		300,000		83,565		846,087		205,980		171,285		231,287		90,596		1,928,800
Mitchell(11)	2006		415,000		14,217		1,457,599		374,958		284,334		719,747		167,546		3,433,401
Costello(12)	2006		351,767		—		850,199		209,755		214,107		415,629		89,081		2,130,538
Hilzinger(13)	2006		315,000		10,846		587,369		101,873		216,911		42,776		58,411		1,333,186

10. Robert K. McDonald, Senior Vice President and CFO.

11. J. Barry Mitchell, President.

12. John T. Costello, Executive Vice President and COO.

13. Matthew F. Hilzinger, Senior Vice President and Controller, Exelon; Chief Accounting Officer, ComEd.

14. In recognition of their overall performance, certain NEOs received an individual performance multiplier (as discussed in the Compensation Discussion and Analysis above) to their annual incentive payment. In addition, Mr. McDonald received a special recognition award during 2006 for his performance with respect to regulatory matters.

15. The amounts shown in this column include the compensation expense recognized in the financial statements for 2006 for the performance share awards granted on January 22, 2007 with respect to the three-year performance period ending December 31, 2006, and the expense recognized during 2006 for performance share awards granted in previous years. For Exelon, Generation and PECO, the amounts shown for Messrs. Skolds, Young, Clark, Crane, O’Brien and Hilzinger, include the expense recognized during 2006 for restricted stock awards made to these officers in previous years which have not yet vested. For ComEd, the amounts shown for all officers include the expense recognized during 2006 for restricted stock awards made to these officers in previous years which have not yet vested. For a discussion of the assumptions made in the valuation of these awards under SFAS No. 123-R, see note 1 to the financial statements. For purposes of this table, estimates of forfeitures related to service-based vesting conditions have been disregarded.

16. The amounts shown in this column include the compensation expense recognized in the financial statements for 2006 for the award of non-qualified options to purchase Exelon common stock granted on January 23, 2006, as well as the expense recognized during 2006 for stock option grants awarded in previous years. Mr. Rowe did not receive a stock option award in 2006; the amount shown represents the expense for grants awarded in previous years. For a discussion of the assumptions made in the valuation of these awards under SFAS No. 123-R, see note 1 to the financial statements. For purposes of this table, estimates of forfeitures related to service-based vesting conditions have been disregarded.

17. The amounts shown in this column represent payments made pursuant to the Annual Incentive Program with respect to 2006 performance. These amounts were awarded on January 22, 2007.

18. The amounts shown in this column represent the change in the accumulated pension benefit from December 31, 2005 to December 31, 2006. Also included in this column is the amount of above-market earnings credited to the officers’ deferred compensation accounts. Out of the basket of mutual funds that executive officers may select for their deferred compensation investment benchmarks, there is one fund which, through its composition, provides earnings which are above 120% of the applicable Federal long-term rate as specified by the IRS. Messrs. Crane, McLean, and McDonald were invested in this investment benchmark during 2006 and their accounts were credited with $57,392, $1,078, and $3,600 respectively of above market earnings.

347

19. The amounts shown in this column include the items summarized in the following tables:

All Other Compensation

Exelon, Generation and PECO

(A)	Perquisites ($) See Note 24 (B)		Reimbursement for Income Taxes ($) See Note 20 (C)		Company Contributions to Savings Plans ($) See Note 21 (D)		Company Paid Term Life Insurance ($) See Note 22 (E)		Dividends on Equity Awards not Included Above ($) See Note 23 (F)		Total All Other Compensation ($) (G)
Rowe	$	181,743	$	21,112	$	64,548	$	308,052	$	—	$	575,455
Skolds		35,419		1,778		31,524		65,847		30,808		165,376
Young		58,777		10,712		27,319		40,285		21,715		158,808
Mehrberg		55,872		12,118		27,819		43,507		5,679		144,995
Clark		33,419		7,663		22,000		83,843		16,000		162,925
McLean		22,842		2,164		22,086		55,510		—		102,602
Crane		31,910		90		25,274		30,413		43,717		131,404
O’Brien		22,556		2,987		19,726		30,007		16,048		91,324
Hilzinger		22,596		—		15,750		3,099		16,966		58,411

ComEd

(A)	Perquisites ($) See Note 24 (B)		Reimbursement for Income Taxes ($) See Note 20 (C)		Company Contributions to Savings Plans ($) See Note 21 (D)		Company Paid Term Life Insurance ($) See Note 22 (E)		Dividends on Equity Awards not Included Above ($) See Note 23 (F)		Total All Other Compensation ($) (G)
Clark	$	33,419	$	7,663	$	22,000	$	83,843	$	16,000	$	162,925
McDonald		27,114		—		15,000		20,351		28,131		90,596
Mitchell		34,127		4,097		20,750		69,530		39,042		167,546
Costello		16,115		—		17,550		39,416		16,000		89,081
Hilzinger		22,596		—		15,750		3,099		16,966		58,411

20. Officers receive a reimbursement to cover applicable taxes on imputed income amounts for business related spousal travel, certain club memberships and relocation expenses because the personal benefit is closely related to the business purpose.

21. Represents company matching contributions to the NEO’s qualified and non-qualified savings plans. The 401(k) plan is available to all employees and the annual contribution for 2006 was generally limited to $15,000. NEOs and other officers may participate in the Deferred Compensation Plan, into which payroll contributions in excess of the specified IRS limit are credited under the separate, unfunded, plan which has the same portfolio of investment options as the 401(k) plan.

22. Exelon provides basic term life insurance, accidental death and disability insurance, and long-term disability insurance to all employees, including NEOs. The values shown in this column include the premiums paid during 2006 for additional term life insurance policies for the NEOs, additional supplemental accidental death and dismemberment insurance and for additional long-term disability insurance over and above the basic coverage provided to all employees. Mr. Rowe has two term life insurance policies and one additional accidental death and dismemberment policy.

23. The amounts shown represent the dividends on current equity awards that have not been included in the values shown in the column labeled Stock Awards in the Summary Compensation Tables above. The values shown represent regular dividends on common stock paid in cash during the year on each officer’s unvested restricted stock, and for certain officers, the value of reinvested regular dividends earned during 2006 on their unvested performance share balances which were distributed in stock upon vesting on January 22, 2007.

Exelon does not provide any discounts on securities purchased through the company other than that offered to all employees who participate in the ESPP, nor does Exelon provide preferential or above-market dividends or earnings to executives through any company plans.

24. The amounts shown in this column represent the incremental cost to Exelon to provide certain perquisites to NEOs as summarized in the following tables:

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Perquisites

Exelon, Generation and PECO

(A)	Personal and Spouse Travel ($) See Note 25 (B)		Automobile Lease and Parking ($) See Note 26 (C)		Financial, Estate and Tax Planning Services ($) See Note 27 (D)		Dining, Health, and Airline Club Memberships ($) See Note 28 (E)		Other ($) See Note 29 (F)		Total ($) (G)
Rowe	$	136,052	$	18,708	$	15,500	$	10,160	$	1,323	$	181,743
Skolds		230		20,653		12,516		2,020		—		35,419
Young		8,333		25,058		21,491		3,895		—		58,777
Mehrberg		8,506		21,502		20,050		5,403		411		55,872
Clark		3,258		22,746		—		6,965		450		33,419
McLean		2,080		20,762		—		—		—		22,842
Crane		114		21,681		9,715		—		400		31,910
O’Brien		2,287		16,011		—		3,683		575		22,556
Hilzinger		—		22,596		—		—		—		22,596

ComEd

(A)	Personal and Spouse Travel ($) See Note 25 (B)		Automobile Lease and Parking ($) See Note 26 (C)		Financial, Estate and Tax Planning Services ($) See Note 27 (D)		Dining, Health, and Airline Club Memberships ($) See Note 28 (E)		Other ($) See Note 29 (F)		Total ($) (G)
Clark	$	3,258	$	22,746	$	—	$	6,965	$	450	$	33,419
McDonald		—		22,014		5,100		—		—		27,114
Mitchell		2,717		21,090		8,835		1,485		—		34,127
Costello		—		15,665		—		—		450		16,115
Hilzinger		—		22,596		—		—		—		22,596

25. Mr. Rowe is entitled to 50 hours of personal use of corporate aircraft each year. The figure shown in this column includes $113,397, representing the aggregate incremental cost to Exelon for Mr. Rowe’s personal use of corporate aircraft. For 2006, 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. From time to time Mr. Rowe’s spouse accompanies Mr. Rowe in his travel on corporate aircraft. The aggregate incremental cost to the company, if any, for Mrs. Rowe’s travel on corporate aircraft is included in the table. For all executive officers, including Mr. Rowe, Exelon pays the cost of spousal 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 spousal travel, meals, and related amenities when attending company or industry-related events. This cost is shown in column B of the All Other Compensation Table above.

The company maintains several vehicles and chauffeurs in order to provide transportation services for the NEOs and other officers to carry out their duties among the company’s various offices and facilities which are located throughout northeastern Illinois and southeastern Pennsylvania. Messrs. Rowe, Clark, and O’Brien are also entitled to limited personal use of the company’s chauffer services, including use for commuting which allows them to work while commuting. The cost included in the table represents the estimated incremental cost to Exelon to provide limited personal service. This cost is based upon the number of hours that the chauffers worked overtime providing services to each NEO, multiplied by the average overtime rate for chauffers plus an additional amount for fuel and maintenance. Personal use was imputed as additional taxable income to Mr. Rowe, Mr. Clark, and Mr. O’Brien.

26. In 2006, Exelon provided 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 may also receive company-paid parking. Officers are imputed additional taxable income for that portion of their use of these perquisites that is personal; however, the figure shown in the table is the total cost to provide the automobile and related amenities to the officer.

27. In 2006, officers were allowed to use financial, estate and tax planning 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.

349

28. In 2006, officers were entitled to club memberships in each of the categories shown for the purpose of conducting business on behalf of the company. 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. Membership in country clubs is not provided or reimbursed.

29. Executive officers may use company-provided vendors for comprehensive physical examinations and related follow-up testing. For Mr. Rowe, the amount shown also reflects the cost of computer equipment installed and maintained in his home.

Grants of Plan-Based Awards

	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards (See Note 1)						Estimated Future Payouts Under Equity Incentive Plan Awards (See Note 2)			All other Stock Awards: Number of Shares or Units (See Note 3) (#)	All Other Options Awards: Number of Securities Under- lying Options (#)	Exercise or base Price of Option Awards ($)		Grant Date Fair Value of Stock and Option Awards (See Note 4) ($)
		Thres- hold ($)		Target ($)		Maximum ($)		Thres- hold (#)	Target (#)	Maxi- mum (#)
[A]	[B]	[C]		[D]		[E]		[F]	[G]	[H]	[I]	[J]	[K]		[L]
Rowe	1/23/2006	$	650,000	$	1,300,000	$	2,600,000
	1/23/2006							34,500	69,000	138,000					$	7,239,590
Skolds	1/23/2006		238,125		476,250		952,500
	1/23/2006							10,000	20,000	40,000						2,098,432
	1/23/2006											43,000	$	58.55		568,460
Young	1/23/2006		192,500		385,000		770,000
	1/23/2006							8,250	16,500	33,000						1,731,206
	1/23/2006											35,000		58.55		462,700
Mehrberg	1/23/2006		196,000		392,000		784,000
	1/23/2006							8,250	16,500	33,000						1,731,206
	1/23/2006											35,000		58.55		462,700
Clark	1/23/2006		143,000		286,000		572,000
	1/23/2006							6,500	13,000	26,000						1,363,981
	1/23/2006											30,000		58.55		396,600
McLean	1/23/2006		133,500		267,000		534,000
	1/23/2006							8,250	16,500	33,000						1,731,206
	1/23/2006											35,000		58.55		462,700
Crane	1/23/2006		153,000		306,000		612,000
	1/23/2006							6,500	13,000	26,000						1,363,981
	1/23/2006											30,000		58.55		396,600
O’Brien	1/23/2006		120,000		240,000		480,000
	1/23/2006							4,500	9,000	18,000						944,294
	1/23/2006											20,000		58.55		264,400
	2/1/2006										5,000					286,100
Hilzinger	1/23/2006		78,750		157,500		315,000
	1/23/2006							2,500	5,000	10,000						524,608
	1/23/2006											10,500		58.55		138,810

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ComEd

	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards (See Note 1)						Estimated Future Payouts Under Equity Incentive Plan Awards (See Note 2)			All other Stock Awards: Number of Shares or Units (See Note 3) (#)	All Other Options Awards: Number of Securities Under- lying Options (#)	Exercise or base Price of Option Awards ($)		Grant Date Fair Value of Stock and Option Awards (See Note 4) ($)
		Thres- hold ($)		Target ($)		Maximum ($)		Thres- hold (#)	Target (#)	Maxi- mum (#)
[A]	[B]	[C]		[D]		[E]		[F]	[G]	[H]	[I]	[J]	[K]		[L]
Clark	1/23/2006	$	143,000	$	286,000	$	572,000
	1/23/2006							6,500	13,000	26,000					$	1,363,981
	1/23/2006											30,000	$	58.55		396,600
McDonald	1/23/2006		75,000		150,000		300,000
	1/23/2006							2,500	5,000	10,000						524,608
	1/23/2006											10,500		58.55		138,810
Mitchell	1/23/2006		124,500		249,000		498,000
	1/23/2006							4,500	9,000	18,000						944,294
	1/23/2006											20,000		58.55		264,047
Costello	1/23/2006		93,750		187,500		375,000
	1/23/2006							2,500	5,000	10,000						524,608
	1/23/2006											10,500		58.55		138,810
Hilzinger	1/23/2006		78,750		157,500		315,000
	1/23/2006							2,500	5,000	10,000						524,608
	1/23/2006											10,500		58.55		138,810

1. NEOs have annual incentive plan target opportunities based on a fixed percentage of their base salary. Under the terms of the incentive plan, threshold performance earns  ¹/2 of the target while the maximum payout is capped at 200% of target. For additional information about the terms of the 2006 annual incentive program, see Compensation Discussion and Analysis above.

2. NEOs have a long-term performance share target opportunity that is a fixed number of performance shares commensurate with the officer’s position. The 2006 Long-Term Performance Share Unit Award Program was based on two measures, Exelon’s Total Shareholder Return (TSR), compounded monthly, for the three-year period ended December 31, 2006, as compared to the TSR for the companies listed in the Dow Jones Utility Index (60% of the award), and Exelon’s three-year TSR, as compared to the companies in the Standard and Poor’s 500 Index (40% of the award). The threshold TSR Position Ranking, for a 50% of target payout, was the 25th percentile; the target, for a 100% payout, was the 50th percentile; and distinguished, for a 200% payout, was the 75th percentile, with payouts interpolated for performance falling between the threshold, target, and distinguished levels. One third of the awarded performance shares vests upon the award date with the balance vesting in January of the next two years.

3. This column shows additional restricted share awards made during the year. Mr. O’Brien received an award that will vest on February 1, 2009. Mr. O’Brien received cash dividends on these shares.

4. This column shows the grant date fair value, calculated in accordance with SFAS No. 123-R, of the performance share awards, stock options and restricted stock granted to each NEO during 2006.

351

Outstanding Equity Awards at Fiscal Year-End

Exelon, Generation and PECO

	Option Awards (See Note 1)					Stock Awards (See Note 2)
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Option Exercise Price ($)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value as of 12/31/2006 of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have not Vested (#)	Equity Incentive Plan Awards: Market Value of Unearned Shares, Units or Other Rights That Have Not Yet Vested ($)
(A)	(B)	(C)	(D)		(E)	(F)	(G)		(H)	(I)
Rowe	192,444 400,000 262,500 200,000 57,250	—   —   87,500 200,000 171,750	$	33.94 23.46 24.81 32.54 42.85	1 Jan 2011 27 Jan 2012 26 Jan 2013 25 Jan 2014 23 Jan 2015	99,124	$	6,134,784	138,000	$	8,540,820
Skolds	15,000 10,000 14,000 —	20,000 40,000 42,000 43,000		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	44,069		2,727,430	40,000		2,475,600
Young	—   —   —   —	7,500 27,000 42,000 35,000		24.63 32.54 42.85 58.55	3 Mar 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	25,395		1,571,697	33,000		2,042,370
Mehrberg	—   20,000 14,000 —	18,000 40,000 42,000 35,000		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	24,814		1,535,738	33,000		2,042,370
Clark	—   27,000 9,000 —	13,500 27,000 27,000 30,000		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	27,322		1,690,959	26,000		1,609,140
McLean	126,000 90,000 9,288 54,000 40,000 14,000 —	—   —   —   18,000 40,000 42,000 35,000		29.75 23.46 24.84 24.81 32.54 42.85 58.55	19 Oct 2010 27 Jan 2012 24 Feb 2012 26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	24,814		1,535,738	33,000		2,042,370
Crane	—   —   —   —	10,000 27,000 27,000 30,000		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	37,322		2,309,859	26,000		1,609,140
O’Brien	8,000 8,000 8,000 8,000 9,000 22,500 10,000 7,250 —	—   —   —   —   —   7,500 20,000 21,750 20,000		9.84 18.84 16.78 18.66 21.91 24.81 32.54 42.85 58.55	22 Feb 2008 23 Feb 2009 16 Dec 2009 27 Feb 2010 31 Jul 2010 26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	16,987		1,051,325	18,000		1,114,020
Hilzinger	—   9,000 3,500 —	4,250 9,000 10,500 10,500		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	14,257		882,366	10,000		618,900

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ComEd

	Option Awards (See Note 1)					Stock Awards (See Note 2)
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Option Exercise Price ($)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value as of 12/31/2006 of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have not Vested (#)	Equity Incentive Plan Awards: Market Value of Unearned Shares, Units or Other Rights That Have Not Yet Vested ($)
(A)	(B)	(C)	(D)		(E)	(F)	(G)		(H)	(I)
Clark	—   27,000 9,000 —	13,500 27,000 27,000 30,000	$	24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	27,322	$	1,690,959	26,000	$	1,609,140
McDonald	—   —   —   —	4,250 9,000 10,500 10,500		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	21,192		1,311,573	10,000		618,900
Mitchell	—   —   5,250 —	7,500 15,000 15,750 20,000		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	30,489		1,886,964	18,000		1,114,020
Costello	—   —   —   —	4,500 10,000 10,500 10,500		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	16,257		1,006,146	10,000		618,9000
Hilzinger	—   9,000 3,500 —	4,250 9,000 10,500 10,500		24.81 32.54 42.85 58.55	26 Jan 2013 25 Jan 2014 23 Jan 2015 22 Jan 2016	14,257		882,366	10,000		618,900

1. Non-qualified stock options are granted to NEOs pursuant to the company’s long-term incentive plans. Grants made prior to 2003 vested in three equal increments, beginning on the first anniversary of the grant date. Grants made in 2003 and thereafter vest in four equal increments, beginning on the first anniversary of the grant date. All grants expire on the tenth anniversary of the grant date. 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 amount shown includes the unvested portion of performance share awards earned with respect to the three-year performance periods ending December 31, 2005 and December 31, 2004, and any unvested restricted awards. The amount of shares shown under equity incentive plan awards: unearned shares represent the maximum number of performance shares available to each NEO for the performance period ending December 31, 2006. Shares are valued at $61.89, the closing price on December 31, 2006.

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Option Exercises and Stock Vested

Exelon, Generation and PECO

	Option Awards			Stock Awards
Name	Number of Shares Acquired on Exercise (#) See Note 1	Value Realized on Exercise ($)		Number of Shares Acquired on Vesting (#) See Note 2	Value Realized on Vesting ($)
(A)	(B)	(C)		(D)	(E)
Rowe	770,000	$	20,349,090	98,178	$	5,748,343
Skolds	137,500		4,056,609	24,145		1,413,707
Young	63,500		1,646,285	21,898		1,276,862
Mehrberg	88,400		2,289,657	24,145		1,413,707
Clark	118,666		3,719,511	16,814		984,473
McLean	—		—	103,995		5,982,484
Crane	32,500		738,404	15,427		903,238
O’Brien	—		—	11,525		674,810
Hilzinger	36,750		1,075,361	6,052		354,321

ComEd

	Option Awards			Stock Awards
Name	Number of Shares Acquired on Exercise (#) See Note 1	Value Realized on Exercise ($)		Number of Shares Acquired on Vesting (#) See Note 2	Value Realized on Vesting ($)
(A)	(B)	(C)		(D)	(E)
Clark	118,666	$	3,719,511	16,814	$	984,473
McDonald	12,250		302,256	5,988		350,576
Mitchell	67,500		2,024,362	9,778		572,482
Costello	13,000		310,893	6,190		362,445
Hilzinger	36,750		1,075,361	6,052		354,321

1. Messrs. Rowe, Skolds, Young, Mehrberg, Clark, and Mitchell exercised all options shown above pursuant to Rule 10b5-1 trading plans that were entered into when the officer was unaware of any material information regarding Exelon that had not been publicly disclosed. The dates of the sales were set at the time the trading plans were established.

2. Share amounts are generally composed of performance shares that vested on January 23, 2006, which included 1/3 of the grant made with respect to the three-year performance period ending December 31, 2005; 1/3 of the grant made with respect to the three-year performance period ending December 31, 2004, and 1/3 of the grant made with respect to the three-year performance period ending December 31, 2003. For Mr. McLean, the amount vested in 2006 also includes 79,849 deferred phantom shares originally granted in 1999 and 2000 by PECO Energy Company. For Mr. Young, the amount vested in 2006 also includes 2,500 restricted shares that were granted in 2003.

Pension Benefits

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 in order to both reduce future retirement benefit costs and provide an option that is portable as the company anticipated a work force that was more mobile that the traditional utility workforce. The cash balance defined benefit pension plans 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

354

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 annual incentive payments, which are disclosed in the Summary Compensation Table for the NEOs. The calculation of retirement benefits under the Exelon Corporation Retirement Program is based upon average earnings for the highest consecutive multi-year period. Messrs. Rowe, Skolds, Mehrberg, Clark, Crane, McDonald, Mitchell, and Costello participate in the Exelon Corporation Retirement Program. Messrs. Young, McLean, O’Brien, and Hilzinger participate in Exelon’s cash balance pension plans.

Under the cash balance pension plan, an account is established for each participant and the account balance grows as a result of annual benefit credits and annual investment credits. Currently, the annual 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 specified in Section 417(e) of the Internal Revenue Code that is used to determine lump sum payments (the interest rate is determined in November of each 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 plans.

The Internal Revenue Code limits to $220,000 as of January 1, 2006 the individual annual compensation that may be taken into account under the tax-qualified retirement plan. As permitted by ERISA, Exelon sponsors supplemental pension plans that 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.

For purposes of the SERP, Mr. Skolds received an additional 7 ¹/2 years of credited service upon his 5^th anniversary of employment and will receive an additional 7 ¹/2 years upon his 10^th anniversary in 2010. These credited years of service were awarded to him when he came to work for the company in 2000 to compensate Mr. Skolds for the pension benefits from his former employer that he surrendered to come to work for the company. Mr. Mehrberg received an additional 10 years of credited service upon his fifth anniversary. He was awarded these credited years of service in 2002 as a retention incentive. Mr. Crane received an additional eight years of credited service through December 31, 2006 as part of his employment offer that provides one additional year of service credit for each year of employment to a maximum of 10 additional years.

Under his employment agreement, Mr. Rowe is entitled to receive a special supplemental executive retirement plan benefit (the SERP benefit) upon termination of employment for any reason other than for cause. The 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 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. In the event Mr. Rowe’s employment had terminated for cause prior to March 16, 2006 (his “normal retirement date” under his original employment agreement), his entire SERP benefit would have been forfeited. Upon a termination for cause on or after March 16, 2006, the portion of the SERP benefit accruing after that date is forfeited.

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 arrangements) are not affected by this policy.

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The amount of the change in the pension value for each of the named executive officers is the amount included in the Summary Compensation Table above in the column headed “Change in Pension Value & Nonqualified Deferred Compensation Earnings.” The present value of each NEO’s accumulated pension benefit is shown in the following tables.

Exelon, Generation and PECO

Name	Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit ($)			Payments During 2006 ($)
(A)	(B)	(C)	(D)			(E)
Rowe	Pension	8.80	$	356,298		$	—
	SERP	28.80		15,177,250	(1)		—
Skolds	Pension	6.36		222,696			—
	SERP	13.86		2,184,923			—
Young	Pension	3.84		54,612			—
	SERP	3.84		170,910			—
Mehrberg	Pension	6.08		155,307			—
	SERP	16.08		1,657,722			—
Clark	Pension	40.00		1,778,218			—
	SERP	40.00		3,708,223			—
McLean	Pension	4.00		53,919			—
	SERP	4.00		144,941			—
Crane	Pension	8.26		176,953			—
	SERP	16.52		1,174,126			—
O’Brien	Pension	24.51		536,225			—
	SERP	24.51		393,673			—
Hilzinger	Pension	4.72		70,903			—
	SERP	4.72		82,322			—

(1) Based on discount rates prescribed by the SEC proxy disclosure guidelines, the present value of Mr. Rowe’s SERP benefit is $15,177,250. Based on lump sum plan rates for immediate distributions, the comparable lump sum amount applicable for service through December 31, 2006 is $18,476,130. Note that, in any event, payments made upon termination may be delayed by six months in accordance with U.S. Treasury Department guidance.

ComEd

Name	Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit ($)		Payments During 2006 ($)
(A)	(B)	(C)	(D)		(E)
Clark	Pension	40.00	$	1,778,218	$	—
	SERP	40.00		3,708,223		—
McDonald	Pension	28.27		817,988		—
	SERP	28.27		759,230		—
Mitchell	Pension	35.50		1,343,900		—
	SERP	35.50		2,498,623		—
Costello	Pension	36.55		1,546,778		—
	SERP	36.55		1,720,220		—
Hilzinger	Pension	4.72		70,903		—
	SERP	4.72		82,322		—

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Nonqualified Deferred Compensation

The following tables show the amounts that NEOs have accumulated under both the Deferred Compensation Plan and the Stock Deferral Plan. Under both plans, officers have notional, or bookkeeping accounts, established in their name. Officers can elect to defer up to 100% of their salary and up to 100% of their Annual Incentive Award into the Deferred Compensation Plan. In addition to these direct deferrals, for the officers who have elected to make contributions to the 401(k) plan and reach the maximum allowable annual contribution, their elected salary deferrals and company matching contributions, if applicable, continue and are credited to their account in the Deferred Compensation Plan. The investment options under the Deferred Compensation Plan consist of a basket of mutual funds benchmarks that mirror those funds available to all employees through the 401(k) plan, with the exception of one benchmark fund that offers a fixed percentage return over a specified market return. Balances in the Deferred Compensation Plan will be settled in cash upon the termination event selected by the officer and will be distributed either in a lump sum, or in annual installments. Deferred amounts generally represent unfunded unsecured obligations of the company.

Officers can also elect to defer up to 100% of their vested performance shares or restricted shares into the Stock Deferral Plan. Each officer has a notional, or bookkeeping account, established in his or her name. Share balances continue to earn the same dividends that are available to all shareholders, which are reinvested as additional shares in the plan. Balances in the plan are distributed in shares of Exelon stock in a lump sum distribution upon termination of employment.

Exelon, Generation and PECO

Name	Executive Contributions in 2006 ($)		Registrant Contributions in 2006 ($)		Aggregate Earnings in 2006 ($)		Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at 12/31/2006 ($)
(A)	(B)		(C)		(D)		(E)		(F)
Rowe	$	53,548	$	53,548	$	3,198,698	$	—	$	19,526,901
Skolds		24,629		20,524		673,082		—		4,217,995
Young		105,956		16,923		59,645		—		513,107
Mehrberg		828,033		17,055		770,605		—		5,280,946
Clark		29,000		14,385		381,568		—		2,351,534
McLean		11,085		11,086		52,405		—		356,796
Crane		161,918		17,654		526,152		—		4,521,999
O’Brien		63,904		15,543		190,934		—		1,352,261
Hilzinger		395,384		4,750		198,003		—		1,565,250

ComEd

Name	Executive Contributions in 2006 ($)		Registrant Contributions in 2006 ($)		Aggregate Earnings in 2006 ($)		Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at 12/31/2006 ($)
(A)	(B)		(C)		(D)		(E)		(F)
Clark	$	29,000	$	14,385	$	381,568	$	—	$	2,351,534
McDonald		196,460		4,000		108,731		—		791,647
Mitchell		305,905		12,933		335,294		—		2,215,108
Costello		7,860		6,550		33,650		—		289,207
Hilzinger		395,384		4,750		198,003		—		1,565,250

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In response to declining plan enrollment and the administrative complexity of compliance with Section 409A of the Internal Revenue Code, the compensation committee approved amendments to the Deferred Compensation and Stock Deferral Plans at its December 4, 2006 meeting. The Deferred Compensation Plan was amended to:

• cease deferrals of base salary and annual incentive awards earned on or after January 1, 2007;

• require distributions in 2007 of deferred annual incentive awards earned in 2006;

• require participants to elect distributions of their account balances payable in a lump sum or annual installments upon retirement, or in a lump sum in the third quarter of 2007; and

• continue to permit deferral of amounts that would have been contributed to the Employee Savings Plan but for applicable IRS limitations.

The Stock Deferral Plan was amended to:

1. cease deferrals of performance share units earned in 2007 or later;

2. require distribution, upon vesting, of non-vested deferred performance share units earned in 2004, 2005 and 2006; and

3. require participants to elect distributions of their remaining account balances payable in a lump sum or installments upon retirement, or in a lump sum during the third quarter of 2007.

Deferred Compensation Plan balance and Stock Deferral Plan balance lump sum distribution elections, 2007 Excess Savings Plan Contribution elections and Retirement Distribution elections for NEOs are summarized in the following table:

Exelon, Generation and PECO

Name	Elected to Receive Deferred Compensation Plan Balances as of 12/31/06 in 3rd Quarter 2007	Elected to Receive Stock Deferral Plan Balances as of 12/31/06 in 3rd Quarter 2007	Elected to Defer into the Deferred Compensation Plan Amounts Contributed to the Exelon Corporation Employee Savings Plan in 2007 that Exceed Applicable IRS Limits	Retirement Distribution Election for any Account Balance Held in the Deferred Compensation Plan or Stock Deferral Plan after the 3rd Quarter of 2007
Rowe	Yes	Yes	Yes	100% Lump Sum
Skolds	Yes	Yes	Yes	100% Lump Sum
Young	Yes	Yes	Yes	100% Lump Sum
Mehrberg	Yes	No	Yes	100% Lump Sum
Clark	Yes	Yes	Yes	100% Lump Sum
McLean	No	No	Yes	100% Lump Sum
Crane	Yes	Yes	Yes	100% Lump Sum
O’Brien	No	No	Yes	100% Lump Sum
Hilzinger	Yes	Yes	Yes	100% Lump Sum

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ComEd

Name	Elected to Receive Deferred Compensation Plan Balances as of 12/31/06 in 3rd Quarter 2007	Elected to Receive Stock Deferral Plan Balances as of 12/31/06 in 3rd Quarter 2007	Elected to Defer into the Deferred Compensation Plan Amounts Contributed to the Exelon Corporation Employee Savings Plan in 2007 that Exceed Applicable IRS Limits	Retirement Distribution Election for any Account Balance held in the Deferred Compensation Plan or Stock Deferral Plan after the 3rd Quarter of 2007
Clark	Yes	Yes	Yes	100% Lump Sum
McDonald	Yes	Yes	Yes	100% Lump Sum
Mitchell	Yes	Yes	Yes	100% Lump Sum
Costello	Yes	Yes	Yes	100% Lump Sum
Hilzinger	Yes	Yes	Yes	100% Lump Sum

Potential Payments upon Termination or Change in Control

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.

In the event Mr. Rowe’s employment terminates for cause after March 16, 2006, the portion of the SERP benefit that accrues after March 16, 2006 is forfeited. Upon any termination for cause, all stock options (whether vested or non-vested) and non-vested performance shares and restricted stock will also 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.

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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 Employment Agreements and Severance Plan Covering Other Named Executives”; 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, 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 of (1) three years and (2) 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 (1) three years and (2) the number of years (including fractional years) remaining until March 16, 2010;

• the SERP benefit will be determined taking into account the lump sum severance payment, 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;

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• 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;

• 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

• 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.

361

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 shareholders retain between 60% and 66²/₃% control (a significant acquisition), if a named executive officer resigns for good reason or if the executive’s employment is terminated by 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;

362

• 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 two 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;

• 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;

363

• 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.

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.

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.

Estimated Value of Benefits to be Received Upon Retirement

The following tables show the estimated value of payments and other benefits to be conferred upon the NEOs assuming they retired as of December 29, 2006. These payments and benefits are in addition to the present value of the accumulated benefits from each NEO’s qualified and non-qualified pension plans shown in the tables within the Pension Benefit section and the aggregate balance due to each NEO that is shown in the tables within the Nonqualified Deferred Compensation section.

Exelon, Generation and PECO

Name	Cash Payment ($) See Note 1		Value of Unvested Equity Awards ($) See Note 2		Perquisites and Other Benefits ($) See Note 3		Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)
Rowe	$	1,642,000	$	22,549,000	$	975,000	$	25,166,000
Skolds		476,000		6,145,000		—		6,621,000
Young		—		—		—		—
Mehrberg		392,000		5,254,000		—		5,646,000
Clark		286,000		3,742,000		—		4,028,000
McLean.		—		—		—		—
Crane		—		—		—		—
O’Brien		—		—		—		—
Hilzinger		—		—		—		—

364

ComEd

Name	Cash Payment ($) See Note 1		Value of Unvested Equity Awards ($) See Note 2		Perquisites and Other Benefits ($) See Note 3		Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)
Clark	$	286,000	$	3,742,000	$	—	$	4,028,000
McDonald		150,000		1,334,000		—		1,484,000
Mitchell		249,000		2,265,000		—		2,514,000
Costello		188,000		1,376,000		—		1,564,000
Hilzinger		—		—		—		—

1. Under the terms of the Company’s Annual Incentive Program, officers receive a pro-rated target incentive award based on the number of days worked during the year of retirement. Mr. Rowe would be entitled to a pro-rated portion of his Formula Annual Incentive as specified by his employment agreement. His Formula Annual Incentive is defined as the greater of the (i) target annual incentive for the year of termination, (ii) the actual annual incentive paid for the latest calendar year ended on or before the termination date, and (ii) the average annual incentive paid for the three years prior to the year of termination (i.e., the 2003, 2004 and 2005 actual annual incentives).

2. The Value of Unvested Equity Awards includes the sum of previously unvested stock options, previously earned but unvested performance share units, a pro-rated target performance share unit award for the year of retirement, and, if applicable (depending upon each officer’s individual restricted stock or restricted stock unit awards (if any)), the value of any unvested restricted stock or restricted stock units that may vest upon retirement. For previously unvested stock options, the value is determined by taking the spread between the closing price of Exelon stock on December 29, 2006, which was $61.89, and the exercise price of each unvested stock option grant, multiplied by the number of unvested options. If an NEO has attained age 50 with 10 or more years of service (or deemed service), his or her unvested stock options will vest upon termination of employment because he or she has satisfied the definition of retirement under the LTIP. For all performance share units and restricted shares or restricted share units, the value is based on the December 29, 2006 closing price of Exelon stock.

3. Pursuant to his employment agreement, Mr. Rowe would be entitled to three years of office and secretarial services and three years of tax, financial and estate planning services.

Estimated Value of Benefits to be Received Upon Termination due to Death or Disability

The following tables show the estimated value of payments and other benefits to be conferred upon the NEOs assuming their employment is terminated due to death or disability as of December 29, 2006. These payments and benefits are in addition to the present value of the accumulated benefits from the NEO’s qualified and non-qualified pension plans shown in the tables within the Pension Benefit section and the aggregate balance due to each NEO that is shown in tables within the Nonqualified Deferred Compensation section.

Exelon, Generation and PECO

Name	Cash Payment ($) See Note 4		Value of Unvested Equity Awards ($) See Note 5		Perquisites and Other Benefits ($) See Note 6		Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)
Rowe	$	1,642,000	$	22,549,000	$	75,000	$	24,266,000
Skolds		476,000		6,764,000		—		7,240,000
Young		385,000		4,372,000		—		4,757,000
Mehrberg		392,000		5,254,000		—		5,646,000
Clark		286,000		4,361,000		—		4,647,000
McLean		267,000		5,254,000		—		5,521,000
Crane		306,000		4,851,000		—		5,157,000
O’Brien		240,000		2,615,000		—		2,855,000
Hilzinger		158,000		1,833,000		—		1,991,000

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ComEd

Name	Cash Payment ($) See Note 4		Value of Unvested Equity Awards ($) See Note 5		Perquisites and Other Benefits ($) See Note 6		Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)
Clark	$	286,000	$	4,361,000	$	—	$	4,647,000
McDonald		150,000		1,953,000		—		2,103,000
Mitchell		249,000		3,194,000		—		3,443,000
Costello		188,000		1,376,000		—		1,564,000
Hilzinger		158,000		1,833,000		—		1,991,000

4. Officers receive a pro-rated target annual incentive award based on the number of days worked during the year of termination. Mr. Rowe would be entitled to a pro-rated portion of his Formula Annual Incentive as specified by his employment agreement. His Formula Annual Incentive is defined as the greater of the (i) target annual incentive for the year of termination, (ii) the actual annual incentive paid for the latest calendar year ended on or before the termination date, and (ii) the average annual incentive paid for the three years prior to the year of termination (i.e., the 2003, 2004 and 2005 actual annual incentives).

5. The Value of Unvested Equity Awards includes the sum of previously unvested stock options, previously earned but unvested performance share units, a pro-rated target performance share unit award for the year of termination, and, if applicable (depending upon each officer’s individual restricted stock or restricted stock unit awards (if any)), the value of any unvested restricted stock or restricted stock units that may vest upon death or disability. For previously unvested stock options, the value is determined by taking the spread between the closing price of Exelon stock on December 29, 2006, which was $61.89, and the exercise price of each unvested stock option grant, multiplied by the number of unvested options. Under the terms of the LTIP, if an optionee terminates employment due to death or disability, all options vest upon termination. For all performance share units and restricted shares or restricted share units, the value is based on the December 29, 2006 closing price of Exelon stock.

6. Pursuant to his employment agreement, Mr. Rowe would be entitled to three years of tax, financial and estate planning services upon termination due to disability, and his estate would receive only one year of such services upon his death.

Estimated Value of Benefits to be Received Upon Involuntary Separation Not Related to a Change in Control

The following tables show the estimated value of payments and other benefits to be conferred upon the NEOs assuming they were terminated as of December 29, 2006 under the terms of the Amended and Restated Senior Management Severance Plan. These payments and benefits are in addition to the present value of the accumulated benefits from the NEO’s qualified and non-qualified pension plans shown in the tables within the Pension Benefit section and the aggregate balance due to each NEO that is shown in the tables within the Nonqualified Deferred Compensation section.

Exelon, Generation and PECO

Name	Cash Payment ($) See Note 7		Retirement Benefit Enhancement ($) See Note 8		Value of Unvested Equity Awards ($) See Note 9		Health & Welfare Benefit Continuation ($) See Note 10		Perquisites and Other Benefits ($) See Note 11		Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)		(F)		(G)
Rowe(11)	$	7,527,000	$	1,888,000	$	22,549,000	$	633,000	$	975,000	$	33,572,000
Skolds		2,699,000		747,000		6,191,000		146,000		65,000		9,848,000
Young		2,255,000		330,000		2,384,000		100,000		40,000		5,109,000
Mehrberg		2,296,000		518,000		5,254,000		106,000		65,000		8,239,000
Clark		1,738,000		367,000		3,742,000		182,000		65,000		6,094,000
McLean		1,691,000		82,000		2,496,000		125,000		40,000		4,434,000
Crane		1,938,000		471,000		2,454,000		80,000		40,000		4,983,000
O’Brien		1,520,000		74,000		1,269,000		79,000		40,000		2,982,000
Hilzinger		749,000		187,000		681,000		15,000		40,000		1,672,000

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ComEd

Name	Cash Payment ($) See Note 7		Retirement Benefit Enhancement ($) See Note 8		Value of Unvested Equity Awards ($) See Note 9		Health & Welfare Benefit Continuation ($) See Note 10		Perquisites and Other Benefits ($) See Note 11		Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)		(F)		(G)
Clark	$	1,738,000	$	367,000	$	3,742,000	$	182,000	$	65,000	$	6,094,000
McDonald		825,000		344,000		1,953,000		44,000		65,000		3,231,000
Mitchell		1,577,000		1,309,000		3,194,000		153,000		65,000		6,298,000
Costello		1,313,000		696,000		1,376,000		87,000		65,000		3,537,000
Hilzinger		749,000		187,000		681,000		15,000		40,000		1,672,000

7. The cash payment is composed of payment equal to a specified multiple of the NEO’s base salary and target annual incentive, plus a pro-rated target annual incentive award based on the number of days worked in the year of termination. Mr. Rowe would be entitled to his Formula Annual Incentive as specified by his employment agreement. His Formula Annual Incentive is defined as the greater of the (i) target annual incentive for the year of termination, (ii) the actual annual incentive paid for the latest calendar year ended on or before the termination date, and (ii) the average annual incentive paid for the three years prior to the year of termination (i.e., the 2003, 2004 and 2005 actual annual incentives). For all officers except Mr. Hilzinger and Mr. McDonald, the multiple used for base salary and annual incentive is 2. For Mr. Hilzinger, the multiple is 1.25 and for Mr. McDonald the multiple is 1.5.

8. The retirement benefit enhancement consists of a one-time lump sum payment based on the actuarial present value of a benefit under the non-qualified pension plan assuming that the benefit was fully vested, the NEO had two additional years of age and two additional years of service, and the severance pay constituted covered compensation for purposes of the non-qualified pension plan. For non-grandfathered executives who are not a part of senior executive management, the severance period is 15 months. In addition, a cash payment will be made in an amount equal to the actuarial present value of any non-vested accrued benefit under Exelon’s qualified pension plan.

9. The Value of Unvested Equity Awards includes the sum of previously unvested stock options, previously earned, but unvested performance share units, a pro-rated target performance share unit award for the year of involuntary separation not related to a change in control, and, if applicable (depending upon each officer’s individual restricted stock or restricted stock unit awards (if any), and the value of any unvested restricted stock that may vest upon involuntary separation not related to a change in control. For previously unvested stock options, the value is determined by taking the spread between the closing price of Exelon stock on December 29, 2006, which was $61.89, and the exercise price of each unvested stock option grant, multiplied by the number of unvested options. If an NEO has attained age 50 with 10 or more years of service (or certain deemed service), his or her unvested stock options will vest upon termination of employment because he or she has satisfied the definition of retirement under the LTIP. For all performance shares or restricted shares, the value is based on the December 29, 2006 closing price of Exelon stock.

10. Estimated costs of heath care, life insurance, and long-term disability coverage that continue during the severance period. For Mr. Rowe, health care, life insurance, and long-term disability coverage will continue for two years.

11. Financial counseling and outplacement services are available for 12 months to executives who have attained age 50 with 10 years or more of service (or deemed service). Upon a termination of Mr. Rowe’s employment due to the company’s failure to appoint or elect him as CEO, Chairman of the Board of Directors and a member of the Board, his benefits are those described under the heading “Estimated Value of Benefits to be Received Upon a Qualifying Termination following a Change in Control”, Mr. Rowe would be entitled to three years of office and secretarial services and three years of tax, financial and estate planning services.

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Estimated Value of Benefits to be Received Upon a Qualifying Termination following a Change in Control

The following tables show the estimated value of payments and other benefits to be conferred upon the NEOs assuming they were terminated upon a qualifying change in control as of December 31, 2006. The company has entered into Change in Control agreements with all of the NEOs except for Messrs. Costello, Hilzinger and McDonald. These payments and benefits are in addition to the present value of accumulated benefits from the NEO’s qualified and non-qualified pension plans shown in the tables within the Pension Benefit section and the aggregate balance due to each NEO that is shown in tables within the Nonqualified Deferred Compensation section.

Exelon, Generation and PECO

Name	Cash Payment ($) See Note 12		Retirement Benefit Enhancement ($) See Note 13		Value of Unvested Equity Awards ($) See Note 14		Health & Welfare Benefit Continuation ($) See Note 15		Perquisites and Other Benefits ($) See Note 16		Excise Tax Gross-up Payment or Scale-back ($) See Note 17		Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)		(F)		(G)		(H)
Rowe	$	10,469,000	$	2,558,000	$	22,549,000	$	949,000	$	1,015,000	Not Required		$	37,540,000
Skolds		3,839,000		1,041,000		6,764,000		220,000		40,000	Not Required			11,904,000
Young		3,503,000		342,000		4,372,000		150,000		40,000	$1,808,000			10,215,000
Mehrberg		3,453,000		911,000		5,254,000		160,000		40,000	Not Required			9,818,000
Clark		2,531,000		454,000		4,980,000		273,000		40,000	Not Required			8,278,000
McLean		2,676,000		139,000		5,254,000		188,000		40,000	Not Required			8,297,000
Crane		2,988,000		887,000		4,851,000		120,000		40,000	Not Required			8,886,000
O’Brien		2,239,000		77,000		2,924,000		118,000		40,000	(173,000	)		5,225,000
Hilzinger		1,221,000		214,000		1,833,000		24,000		40,000	(675,000	)		2,657,000

ComEd

Name	Cash Payment ($) See Note 12		Retirement Benefit Enhancement ($) See Note 13		Value of Unvested Equity Awards ($) See Note 14		Health & Welfare Benefit Continuation ($) See Note 15		Perquisites and Other Benefits ($) See Note 16		Excise Tax Gross-up Payment or Scale-back ($) See Note 17			Total Value of all Payments and Benefits ($)
(A)	(B)		(C)		(D)		(E)		(F)		(G)			(H)
Clark	$	2,531,000	$	454,000	$	4,980,000	$	273,000	$	40,000		Not Required		$	8,278,000
McDonald		1,144,000		566,000		2,262,000		59,000		40,000		Not Required			4,071,000
Mitchell		2,419,000		1,571,000		3,503,000		230,000		40,000	$	(327,000	)		7,436,000
Costello		1,313,000		696,000		1,995,000		87,000		40,000		Not Required			4,131,000
Hilzinger		1,221,000		214,000		1,833,000		24,000		40,000		(675,000	)		2,657,000

12. Cash payment includes a severance payment and the NEO’s target annual incentive award for the year of termination. For Mr. Rowe, the severance payment is equal to three times his current base salary and his Formula Annual Incentive. His Formula Annual Incentive is defined as the greater of the (i) target annual incentive for the year of termination, (ii) the actual annual incentive paid for the latest calendar year ended on or before the termination date, and (ii) the average annual incentive paid for the three years prior to the year of termination (i.e., the 2003, 2004 and 2005 actual annual incentives). For all other NEOs, except Messrs. Costello, Hilzinger, and McDonald, the severance payment is equal to three times the NEO’s current base salary and severance incentive. For Messrs. Costello, Hilzinger, and McDonald, the severance payment is equal to two times their current base salary and severance incentive. Pursuant to their respective employment agreements, Mr. Mitchell will receive an additional payment of $110,000, Mr. O’Brien $35,000, and Mr. Young $45,000.

13. The retirement benefit enhancement consists of a one-time lump sum payment based on the actuarial present value of a benefit under the non-qualified pension plan assuming that the benefit was fully vested, the NEO had three additional years of age and three additional years of service, and the severance pay constituted covered compensation for purposes of the non-qualified pension plan. For non-grandfathered executives who are not a part of senior executive management, the severance period is 24 months. In addition, a cash payment will be made in an amount equal to the actuarial present value of any non-vested accrued benefit under Exelon’s qualified pension plan.

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14. The Value of Unvested Equity Awards includes the sum of previously unvested stock options, previously earned, but unvested performance share units, a pro-rated target performance share unit award for the year of termination following a change in control, and, if applicable (depending upon each officer’s individual restricted stock or restricted stock unit awards (if any), and the value of any unvested restricted stock or restricted stock units that may vest upon termination following a change in control. For previously unvested stock options, the value is determined by taking the spread between the closing price of Exelon stock on December 29, 2006, which was $61.89, and the exercise price of each unvested stock option grant multiplied by the number of unvested options. All unvested stock options will vest upon termination of employment due to a change in control. For all performance share units and restricted shares or restricted stock units, the value is based on the December 29, 2006 closing price of Exelon stock.

15. Estimated costs of heath care, life insurance, and long-term disability coverage that continue during the severance period.

16. Outplacement services are also available for 12 months to all NEOs. Mr. Rowe would also be entitled to three years of office and secretarial services and three years of tax, financial and estate planning services.

17. Represents the estimated value of the required excise tax gross-up payment or scaleback. All of the executives, with the exception of Messrs. Costello, Hilzinger and McDonald, are entitled to an excise tax gross-up payment under their change-in-control employment agreements if the present value of their parachute payments exceed the amount permitted by the IRS by more than 10% and would be subject to the excise tax under Section 4999 of the Internal Revenue Code. If their payments exceed the threshold by less than 10%, their parachute payments are scaled back to the greatest amount payable that would not trigger the excise tax. With respect to Messrs. Costello, Hilzinger and McDonald, if their parachute payments exceed the amount permitted by the IRS, their parachute payments are scaled back to the greatest amount payable that would not trigger the excise tax under Section 4999 of the Internal Revenue Code. Pursuant to Section 8.5 of his employment agreement, Mr. Rowe is entitled to an excise tax gross-up payment if any payment or benefit received from Exelon is subject to any excise tax under Section 4999 of the Internal Revenue Code.

Non-Employee Director Compensation

Exelon

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.

	Committee Membership	Fees Earned or Paid in Cash				Stock Awards		Change in Pension Value and Nonqualified Compensation Earnings		Total
		Annual Board & Committee Retainers		Board & Committee Meeting Fees
Edward A. Brennan	2 (Ch), 3	$	40,000	$	37,500	$	60,000			$	137,500
M. Walter D’Alessio	1, 2, 3 (Ch)		45,000		54,000		60,000				159,000
Nicholas DeBenedictis	4, 5		40,000		37,500		60,000				137,500
Bruce DeMars	4, 5 (Ch)		45,000		40,500		60,000				145,500
Nelson A. Diaz	5, 6		40,000		49,500		60,000				149,500
Sue L. Gin	1, 6 (Ch)		45,000		40,500		60,000				145,500
Rosemarie B. Greco	2, 4 (Ch)		40,000		33,000		60,000				133,000
Edgar D. Jannotta	3, 6		35,000		30,000		60,000				125,000
John M. Palms	1 (Ch), 5, 6		50,000		51,000		60,000	$	6,066		167,066
William C. Richardson	1, 4, 6		40,000		46,500		60,000				146,500
Thomas J. Ridge	4		37,500		22,500		60,000				120,000
John W. Rogers, Jr	3, 4, 6		35,000		34,500		60,000				129,500
Ronald Rubin	2, 6		35,000		33,000		60,000		2,104		130,104
Richard L. Thomas	1, 2, 3		40,000		54,000		60,000				154,000
Total All Directors		$	567,500	$	564,000	$	840,000	$	8,170	$	1,979,670

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Committee Membership Key

Audit = 1, Compensation = 2, Corporate Governance = 3, Energy Delivery Oversight = 4, Generation Oversight = 5, Risk Oversight = 6

Fees Earned or Paid in Cash

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 and additional $5,000 per year membership retainer.

Directors receive $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 meeting fee for attending the annual shareholders meeting, and annual strategy retreat. Through October, 2006 directors also received a $1,500 per diem fee for their attendance or participation in industry events at the request of Exelon and for attending approved orientation or continuing education programs. In October 2006, the corporate governance committee acted to eliminate the payment of any further per diem fees.

Directors may elect to defer any portion their cash compensation into a non-qualified multi-fund deferred compensation plan. Each director has a record keeping 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 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.

Stock Awards

Directors are required under the Exelon Corporate Governance Principles to own 6,000 shares of Exelon common stock or deferred Exelon common stock units within three years after their election to the board. At a stock price of $60, the ownership requirement is equivalent to $360,000, or approximately ten times the annual cash retainer. This requirement is significantly in excess of the minimum three times annual cash retainer stock ownership requirements recommended by corporate governance groups such as Institutional Shareholder Services. The ownership requirement is intended to align the interests of directors with the interests of shareholders so that directors benefit when Exelon’s stock price increases and suffer when it declines. Rather than paying directors entirely in cash, Exelon pays a significant portion of director compensation in the form of deferred stock units. The deferred stock units are not paid out to the directors until they retire from the board, leaving these amounts at risk during the director’s entire tenure on the board.

All directors receive $60,000 worth of deferred Exelon common stock units per year, which accrue at the end of each calendar quarter 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 record keeping account maintained by the company and earn the same dividends available to all holders of Exelon common stock, which are reinvested in the account as additional units.

As of December 31, 2006 the directors held the following amounts of deferred Exelon common stock units. The units are valued at the closing price of Exelon common stock on December 31, 2006, which was $61.89. Legacy plans include those stock units earned from Exelon’s predecessor companies, PECO Energy Company and Unicom Corporation. For three directors who served on the PECO Energy board of directors, a portion of the legacy deferred stock units was granted as a conversion of the accrued benefits under the PECO Energy Directors Retirement Plan when the plan

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was terminated in 1997. Mr. D’Alessio was first elected to the PECO Energy board in 1983; Dr. Palms was first elected in 1990, and Mr. Rubin was first elected in 1988. For Adm. DeMars and Mr. Jannotta, a portion of the legacy deferred stock units were granted as a conversion of the accrued benefits under the Unicom Directors Retirement plan when the plan was terminated in 1997. Ms. Gin also had 2,779 stock units from this plan that were distributed to her during 2006, pursuant to her election, upon her 65^th birthday. Mr. Brennan was also a participant in this plan, however he made an irrevocable election to receive deferred cash upon his retirement instead of stock. His cash balance under the plan, as of 12/31/2006 is $35,541.

	Year First Elected to the Board	Deferred Stock Units From Legacy Plans	Deferred Stock Units From Exelon Plan	Total Deferred Stock Units	Fair Market Value as of 12/31/2006
Edward A. Brennan	1995	3,870	10,378	14,248	$	881,804
M. Walter D’Alessio	1983	23,414	10,378	33,792		2,091,391
Nicholas DeBenedictis	2002	0	7,284	7,284		450,809
Bruce DeMars	1996	1,209	10,378	11,587		717,147
Nelson A. Diaz	2004	0	3,627	3,627		224,489
Sue L. Gin	1993	0	10,378	10,378		642,304
Rosemarie B. Greco	1998	5,669	10,378	16,047		993,184
Edgar D. Jannotta	1994	12,905	10,378	23,283		1,440,979
John M. Palms	1990	17,808	10,378	28,186		1,744,413
William C. Richardson	2005	0	2,037	2,037		126,049
Thomas J. Ridge	2005	0	1,811	1,811		112,088
John W. Rogers, Jr	1999	3,259	10,378	13,637		843,979
Ronald Rubin	1988	23,295	10,378	33,673		2,084,012
Richard L. Thomas	1998	8,694	10,378	19,072		1,180,351

Deferred Compensation

Directors may elect to defer any portion their cash compensation in a non-qualified multi-fund deferred compensation plan. Each director has an unfunded account where the dollar balance can be invested in one or more of several mutual funds, including one fund composed entirely of Exelon common stock. Fund balances (including those amounts invested in the Exelon common stock fund) will be paid out in cash and may be distributed in a lump sum or in annual installment payments upon a director’s reaching age 65 or upon retirement from the board. These funds are identical to those that are available to executive officers and are generally identical to those available to company employees who participate in the Exelon Employee Savings Plan. Directors and executive officers do have one additional fund not available to employees that, through its composition, does provide returns that for 2006 were found to be in excess of 120% of the federal long-term rate that is used by the IRS to determine above market returns. Dr. Palms and Mr. Rubin had balances in this fund during 2006, and the portion of their earnings which are in excess of the IRS criteria are included in the table.

Other Compensation

Exelon pays the cost of a director’s spouse’s travel, meals, lodging and other related amenities when the spouses are invited to attend company or industry related events where it is customary and expected that directors 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 there is no incremental cost to Exelon of providing transportation and lodging for a director’s spouse when he or she accompanies the director, and the only additional costs to Exelon are those for meals and other amenities and to reimburse the director for the taxes on the imputed income. In 2006, incremental cost to the company to provide these perquisites was less than $10,000 per director and the aggregate

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amount for all directors as a group was $22,275. The aggregate amount paid to all directors as a group for reimbursement of taxes on imputed income was $17,709.

Directors are also reimbursed for reasonable travel from their primary residence and lodging expenses incurred in attending board and committee meetings and when attending other events on behalf of Exelon, including director’s orientation or continuing director’s education programs, facility visits or other business related activities. Exelon charters private aircraft to transport directors to meetings in order to maximize the time available for meeting and discussion. To facilitate communication with directors who are retired and do not have an office staff, Exelon offered director, under a pilot program, the use of a company-provided personal electronic device that can receive both data and voice communications. In October, 2006, the board discontinued the pilot program and directors were given the option to return the devices or to continue using them at their own cost. Exelon has a matching gift program available to employees that matches their contributions to educational institutions up to $5,000 per year. The same program is available to members of the board of directors.

Generation

Exelon Generation Co. LLC does not have a board of directors.

ComEd

For their service as directors of the company, ComEd’s non-employee directors, who are also members of the Exelon board of 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. Non-employee directors who are not members of the Exelon board receive, in addition to the $1,500 meeting fee, an annual retainer of $70,000. All retainers and meeting fees are paid in cash at the end of each quarter. 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.

		Fees Earned or Paid in Cash
	Committee Membership	Annual Board & Committee Retainers		Board & Committee Meeting Fees		Total
James W. Compton		$	19,973	$	7,500	$	27,473
Sue L. Gin	1		—		27,000		27,000
Edgar D. Jannotta	1		—		27,000		27,000
Edward J. Mooney			14,647		6,000		20,647
John W. Rogers, Jr.	1(Ch)		—		33,000		33,000
Jesse H. Ruiz			14,647		7,500		22,147
Richard L. Thomas	1		—		33,000		33,000
Total All Directors		$	49,267	$	141,000	$	190,267

Committee Membership Key

Audit = 1

PECO

The board of directors of PECO Energy Company is composed solely of officers of Exelon and PECO. These officers receive no additional compensation for their service on the PECO board.

372

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Exelon, Generation and PECO

The following table shows the ownership of Exelon common stock as of December 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 named executive officer in the Summary Compensation Table, and for all directors and executive officers as a group.

	[A]	[B]	[C]	[D] = [A] + [B] + [C]	[E]	[F] = [D] + [E]
	Beneficially Owned Shares	Shares Held in Company Plans (See Note 1)	Vested Stock Options and Options that Vest Within 60 Days	Total Shares Held	Share Equivalents to be Settled in Cash or Stock (See Note 2)	Total Share Interest
5% Holders (see note 3)
Capital Research and Management Company	50,513,900	—	—	50,513,900	—	50,513,900
Directors
Edward A. Brennan	8,479	14,248	—	22,727	13,244	35,971
M. Walter D’Alessio	11,235	33,792	—	45,027	—	45,027
Nicholas DeBenedictis	1,000	7,284	—	8,284	—	8,284
Bruce DeMars	9,695	11,587	—	21,282	—	21,282
Nelson A. Diaz	1,500	3,627	—	5,127	1,176	6,303
Sue L. Gin	30,247	10,378	—	40,625	8,443	49,068
Rosemarie B. Greco	2,000	16,048	—	18,048	6,129	24,177
Edgar D. Jannotta	13,240	23,283	—	36,523	10,451	46,974
John M. Palms	2,760	28,186	—	30,946	—	30,946
William C Richardson	1,224	2,036	—	3,260	—	3,260
Thomas J. Ridge	—	1,796	—	1,796	—	1,796
John W. Rogers, Jr.	11,374	13,637	—	25,011	6,600	31,611
Ronald Rubin	15,490	33,673	—	49,163	931	50,094
Richard L. Thomas	22,533	19,072	—	41,605	9,643	51,248
Named Officers
John W. Rowe	240,679	286,358	1,356,944	1,883,981	133,201	2,017,182
John L. Skolds	20,809	79,681	103,750	204,240	32,451	236,691
John F. Young	25,801	2,500	43,750	72,051	23,950	96,001
Randall E. Mehrberg	—	65,814	94,750	160,564	27,097	187,661
Frank M. Clark	22,097	36,057	79,500	137,654	29,261	166,915
Ian P. McLean	47,822	4,601	394,038	446,461	25,915	472,376
Christopher M. Crane	2,766	50,797	40,000	93,563	20,589	114,152
Denis O’Brien	19,496	10,959	110,500	140,955	13,907	154,862
Matthew F. Hilzinger	—	21,147	27,375	48,522	6,916	55,438
Total
Directors & Executive Officers as a group, 28 people. (See Note 4)	560,935	882,839	2,577,457	4,021,231	432,989	4,454,219

1. The shares listed under Shares Held in Company Plans, Column [B], include restricted shares, shares held in the 401(k) plan, and deferred shares held in the Stock Deferral Plan.

2. The shares listed above under Share Equivalents to be Settled in Cash, Column [E], include unvested performance shares that may settled in cash or stock 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.

3. In a Schedule 13G filed with the SEC on February 12, 2007, an investment advisor, Capital Research and Management Company, 333 South Hope Street, Los Angeles, CA 90071, disclosed that as of December 29, 2006, it is deemed to be the beneficial owner of 50,513,900 shares, or approximately 7.5% 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 50,513,900 shares.

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.

373

Securities Authorized for Issuance under Exelon 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	19,187,794	(a)	$	37.72	28,424,990	(b)
Equity compensation plans not approved by security holders	409,942	(c)		20.58	—
Total	19,597,736		$	37.35	28,424,990

(a) Includes 222,626 of deferred stock units earned by non-employee directors under approved plans.

(b) Excludes securities to be issued upon exercise of outstanding options.

(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.

No Generation securities are authorized for issuance under equity compensation plans, and no PECO securities are authorized for issuance under equity compensation plans.

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 December 31, 2006 by (1) any director of ComEd, (2) each named executive officer of ComEd named in the Summary Compensation Table, and (3) all directors and executive officers of ComEd as a group.

	[A]	[B]	[C]	[D] = [A] + [B] + [C]	[E]	[F] = [D] + [E]
	Beneficially Owned Shares	Shares Held in Exelon Plans (See Note 1)	Vested Stock Options and Options that Vest Within 60 Days	Total Shares Held	Share Equivalents to be Settled in Cash or Stock (See Note 2)	Total Share Interest
Directors
James W. Compton	14,790	—	—	14,790	—	14,790
Sue L. Gin	30,247	10,378	—	40,625	8,443	49,068
Edgar D. Jannotta	13,240	23,283	—	36,523	10,451	46,974
Edward J. Mooney		—	—		—
John W. Rogers, Jr.	11,374	13,637	—	25,011	6,600	31,611
Jesse H. Ruiz		—	—		—
Richard L. Thomas	22,533	19,072	—	41,605	9,643	51,248
Named Officers
Frank M. Clark	22,097	36,057	79,500	137,654	29,261	166,915
Robert K. McDonald	9,565	23,837	14,875	47,277	6,325	54,602
J. Barry Mitchell	8,071	51,036	30,500	89,607	16,074	105,681
John T. Costello	18,105	10,431	15,625	44,161	7,064	51,225
Matthew F. Hilzinger	—	21,147	27,375	48,522	6,916	55,438
Total
Directors & Executive Officers as a group, 14 people.	160,839	216,878	213,900	591,617	111,029	702,646

374

1. The shares listed under Shares Held in Exelon Plans, Column [B], include restricted shares, shares held in the 401(k) plan, and deferred shares held in the Stock Deferral Plan.

2. The shares listed above under Share Equivalents to be Settled in Cash, Column [E], include unvested performance shares that may settled in cash or stock 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.

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.”

Stock ownership guidelines

Officers of Exelon and its subsidiaries are required to own certain amounts of Exelon common stock by the later of five years after their employment or promotion to their current position. The objective is to encourage officers to think and act like owners. The ownership guidelines were recalibrated in November 2006 (retroactive to September 30, 2006) and are expressed as both a fixed number of shares and a multiple of annualized base salary to avoid arbitrary changes to the ownership requirements that could arise from ordinary course volatility in the market price for Exelon’s shares. The minimum stock ownership targets by level are the lesser of the fixed number of shares or the multiple of annualized base salary. The number of shares was determined by taking the following multiples of the officer’s base salary as of the latest of October 24, 2006 or the date of hire or promotion: (1) Chairman and CEO, five times base salary; (2) executive vice presidents, three times base salary; (3) Presidents and senior vice presidents, two times base salary; and (4) vice presidents and other executives, one times base salary. Ownership is measured by valuing an executive’s holdings using the 60-day average price of Exelon common stock as of the appropriate date. Shares held outright, earned non-vested performance shares, and deferred shares count toward the ownership guidelines; unvested restricted stock and all stock options do not count for this purpose. As of December 31, 2006, the NEOs held the following amounts of stock relative to the applicable guidelines:

Exelon, Generation and PECO

Name	Ownership Multiple	Ownership Guideline in Shares	Share or Share Equivalents Owned	Ownership as a % of Guideline
Rowe	5x	107,920	660,238	612	%
Skolds	3x	31,629	113,686	359	%
Young	3x	27,395	49,752	182	%
Mehrberg	3x	27,893	92,911	333	%
Clark	3x	21,916	77,415	353	%
McLean	3x	22,165	78,338	353	%
Crane	2x	16,935	54,152	320	%
O’Brien	2x	13,282	39,363	296	%
Hilzinger	2x	10,000	20,063	201	%

ComEd

Name	Ownership Multiple	Ownership Guideline in Shares	Share or Share Equivalents Owned	Ownership as a % of Guideline
Clark	3x	21,916	77,415	353	%
McDonald	2x	9,962	24,727	248	%
Mitchell	2x	13,781	55,180	400	%
Costello	2x	12,452	25,600	206	%
Hilzinger	2x	10,000	20,063	201	%

375

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Exelon

The information required by Item 13 relating to transactions with related persons and director independence is incorporated herein by reference to information to be filed in the 2007 Exelon Proxy Statement.

ComEd

Sidley Austin LLP provided legal services to Exelon and ComEd during 2006. The spouse of Mr. Ruiz, a member of the ComEd board of directors since October 2006, is a partner of Sidley Austin LLP.

The ComEd board of directors has adopted the independence standards of The New York Stock Exchange as its independence standards. In assessing the independence of its directors, the ComEd board considered the relationships of its directors with Exelon as well as the business and charitable relationships among Exelon, ComEd and businesses and charities with which its directors are affiliated. In considering the independence of Mr. Compton, the ComEd board considered Mr. Compton’s prior service as a director of Unicom Corporation and ComEd, contributions made by Exelon and ComEd to Mr. Compton’s former employer, the Chicago Urban League, Mr. Compton’s service on the advisory board of CORE, Consumers Organized for Reliable Electricity, and Mr. Compton’s involvement as a board member or advisory board member with a number of Chicago-area civic and charitable organizations. With respect to Mr. Ruiz, the ComEd board considered the relationship of his spouse with a law firm that provides legal services to Exelon and ComEd, as disclosed above, as well as Exelon’s support of charitable organizations with which Mr. Ruiz has a relationship. With respect to Mr. Mooney, the ComEd board considered the fact that several companies with which Mr. Mooney is affiliated may receive electricity or gas delivery services from ComEd and/or PECO under tariffed rates and Exelon’s support of charitable organizations with which Mr. Mooney has a relationship The board determined that none of these relationships was material and accordingly that Messrs. Compton, Ruiz and Mooney are independent.

Generation and PECO

None. Generation does not have an independent board of directors, and all of the directors of PECO are not independent by virtue of being officers or employees of Exelon or PECO.

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.

376

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, 2006 and 2005, 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)	2006		2005
Audit fees	$	8,230	$	6,818
Audit related fees(a)		3,503		2,743
Tax fees (b)		339		294
All other fees(c)		38		40

(a) Audit related fees consist of assurance and related services that are traditionally performed by the auditor. 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. The fees associated with the proposed PSEG Merger were reclassified to audit related fees from audit fees as the proposed Merger terminated in 2006.

(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.

Generation, ComEd and PECO

Generation, ComEd and PECO are indirect controlled subsidiaries of Exelon and only ComEd has a separate audit committee. That function is fulfilled for Generation and PECO and to some extent ComEd by the Exelon Audit Committee. See ITEM 10. Directors, Executive Officers of the Registrant and Corporate Governance for further information on the Exelon and ComEd audit committees. 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.

377

The following tables present fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of Generation’s, ComEd’s and PECO’s annual financial statements for the years ended December 31, 2006 and 2005, 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.

Generation

	Year Ended December 31,
(in thousands)	2006		2005
Audit fees	$	3,604	$	2,723
Audit related fees(a)		808		—
Tax fees(b)		102		109
All other fees		16		10

(a) Audit related fees consist of assurance and related services that are traditionally performed by the auditor. 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.

ComEd

	Year Ended December 31,
(in thousands)	2006		2005
Audit fees	$	2,485	$	2,164
Audit related fees(a)		599		79
Tax fees(b)		120		43
All other fees		12		8

(a) Audit related fees consist of assurance and related services that are traditionally performed by the auditor. 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)	2006		2005
Audit fees	$	1,452	$	1,265
Audit related fees(a)		388		31
Tax fees(b)		107		25
All other fees		7		4

(a) Audit related fees consist of assurance and related services that are traditionally performed by the auditor. 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.

378

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	Financial Statements and Financial Statement Schedules
(1)	Exelon
(i)	FinancialStatements
	Consolidated Statements of Operations for the years 2006, 2005 and 2004
	Consolidated Statements of Cash Flows for the years 2006, 2005 and 2004
	Consolidated Balance Sheets as of December 31, 2006 and 2005
	Consolidated Statements of Changes in Shareholders’ Equity for the years 2006, 2005 and 2004
	Consolidated Statements of Comprehensive Income for the years 2006, 2005 and 2004
	Notes to Consolidated Financial Statements
(ii)	FinancialStatement Schedule

379

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, 2006
Allowance for uncollectible accounts	$	77	$	94		$	19	(a)	$	99	(b)	$	91
Deferred tax valuation allowance		37		—			—			—			37
Reserve for obsolete materials		26		2			—			1			27
For The Year Ended December 31, 2005
Allowance for uncollectible accounts	$	93	$	77		$	13	(a)	$	106	(b)	$	77
Deferred tax valuation allowance		17		(1	)		21			—			37
Reserve for obsolete materials		28		(2	)		—			—			26
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	110	$	87		$	2		$	106	(b)	$	93
Deferred tax valuation allowance		11		2			4			—			17
Reserve for obsolete materials		18		17			1			8			28

(a) Primarily charges for late payments and non-service receivables.

(b) Write-off of individual accounts receivable.

380

(2)	Generation
(i)	FinancialStatements
		Consolidated Statements of Operations for the years 2006, 2005 and 2004
		Consolidated Statements of Cash Flows for the years 2006, 2005 and 2004
		Consolidated Balance Sheets as of December 31, 2006 and 2005
		Consolidated Statements of Changes in Member’s Equity for the years 2006, 2005 and 2004
		Consolidated Statements of Comprehensive Income for the years 2006, 2005 and 2004
		Notes to Consolidated Financial Statements
(ii)	Financial Statement Schedule

381

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
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, 2006
Allowance for uncollectible accounts	$	15	$	2		$	—		$	—		$	17
Deferred tax valuation allowance		34		—			(1	)		—			33
Reserve for obsolete materials		23		1			—			—			24
For The Year Ended December 31, 2005
Allowance for uncollectible accounts	$	19	$	—		$	(2	)	$	(2	)	$	15
Deferred tax valuation allowance		13		—			21			—			34
Reserve for obsolete materials		24		(1	)		—			—			23
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	14	$	2		$	4		$	1		$	19
Deferred tax valuation allowance		8		1			4			—			13
Reserve for obsolete materials		9		18			—			3			24

382

(3)	ComEd
(i)	FinancialStatements
		Consolidated Statements of Operations for the years 2006, 2005 and 2004
		Consolidated Statements of Cash Flows for the years 2006, 2005 and 2004
		Consolidated Balance Sheets as of December 31, 2006 and 2005
		Consolidated Statements of Changes in Shareholders’ Equity for the years 2006, 2005 and 2004
		Consolidated Statements of Comprehensive Income for the years 2006, 2005 and 2004
		Notes to Consolidated Financial Statements
(ii)	Financial Statement Schedule

383

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, 2006
Allowance for uncollectible accounts	$	20	$	33		$	14	(a)	$	47	(b)	$	20
Reserve for obsolete materials		2		1			—			—			3
For The Year Ended December 31, 2005
Allowance for uncollectible accounts	$	16	$	24		$	18	(a)	$	38	(b)	$	20
Reserve for obsolete materials		3		(1	)		—			—			2
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	16	$	37		$	—		$	37	(b)	$	16
Reserve for obsolete materials		8		(1	)		1			5			3

(a) Charges for late payments and non-service receivables.

(b) Write-off of individual accounts receivable.

384

(4)	PECO
(i)	Financial Statements
		Consolidated Statements of Operations for the years 2006, 2005 and 2004
		Consolidated Statements of Cash Flows for the years 2006, 2005 and 2004
		Consolidated Balance Sheets as of December 31, 2006 and 2005
		Consolidated Statements of Changes in Shareholders’ Equity for the years 2006, 2005 and 2004
		Consolidated Statements of Comprehensive Income for the years 2006, 2005 and 2004
		Notes to Consolidated Financial Statements
(ii)	Financial Statement Schedule

385

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, 2006
Allowance for uncollectible accounts	$	39	$	58	$	5	$	51	(a)	$	51
Reserve for obsolete materials		1		—		—		—			1
For The Year Ended December 31, 2005
Allowance for uncollectible accounts	$	52	$	45	$	4	$	62	(a)	$	39
Reserve for obsolete materials		1		—		—		—			1
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	72	$	47	$	1	$	68	(a)	$	52
Reserve for obsolete materials		—		1		—		—			1

(a) Write-off of individual accounts receivable.

386

(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. 0-01401, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1).
3-1	Articles of Incorporation of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-1).
3-2	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 Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).
3-4	Bylaws of PECO Energy Company, adopted February 26, 1990 and amended January 26, 1998 (File No. 1-01401, 1997 Form 10-K, Exhibit 3-2).
3-5	Restated Articles of Incorporation of Commonwealth Edison Company effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 Cumulative Preference Stock” (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2).
3-6	Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).
3-7	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).
3-8	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).
3-9	Amended and Restated By-Laws of Commonwealth Edison Company, effective January 23, 2006 (File No. 1-1839, Form 8-K dated January 23, 2006, Exhibit 99.1).
3-10	Amended and Restated Bylaws of Exelon Corporation (File No. 1-16169, Form 8-K dated December 5, 2006, Exhibit 3.1).
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).
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)

387

	Dated as of	File Reference	Exhibit No.
	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
	September 15, 2006	000-16844, Form 8-K dated September 25, 2006	4.1
4-2	Exelon Corporation Dividend Reinvestment and Stock Purchase Plan (Registration Statement No. 333-84446, Form S-3, Prospectus).
4-3	Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Midwest Trust Company, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (File No. 2-60201, Form S-7, Exhibit 2-1).
4-3-1	Supplemental Indentures to aforementioned Commonwealth Edison Mortgage.
	Dated as of	File Reference	Exhibit No.
	August 1, 1946	2-60201, Form S-7	2-1
	April 1, 1953	2-60201, Form S-7	2-1
	March 31, 1967	2-60201, Form S-7	2-1
	April 1,1967	2-60201, Form S-7	2-1
	February 28, 1969	2-60201, Form S-7	2-1
	May 29, 1970	2-60201, Form S-7	2-1
	June 1, 1971	2-60201, Form S-7	2-1
	April 1, 1972	2-60201, Form S-7	2-1
	May 31, 1972	2-60201, Form S-7	2-1
	June 15, 1973	2-60201, Form S-7	2-1

388

Dated as of	File Reference	Exhibit No.
May 31, 1974	2-60201, Form S-7	2-1
June 13, 1975	2-60201, Form S-7	2-1
May 28, 1976	2-60201, Form S-7	2-1
June 3, 1977	2-60201, Form S-7	2-1
May 17, 1978	2-99665, Form S-3	4-3
August 31, 1978	2-99665, Form S-3	4-3
June 18, 1979	2-99665, Form S-3	4-3
June 20, 1980	2-99665, Form S-3	4-3
April 16, 1981	2-99665, Form S-3	4-3
April 30, 1982	2-99665, Form S-3	4-3
April 15, 1983	2-99665, Form S-3	4-3
April 13, 1984	2-99665, Form S-3	4-3
April 15, 1985	2-99665, Form S-3	4-3
April 15, 1986	33-6879, Form S-3	4-9
June 15, 1990	33-38232, Form S-3	4-12
October 1, 1991	33-40018, Form S-3	4-13
October 15, 1991	33-40018, Form S-3	4-14
May 15, 1992	33-48542, Form S-3	4-14
September 15, 1992	33-53766, Form S-3	4-14
February 1, 1993	1-1839, 1992 Form 10-K	4-14
April 1, 1993	33-64028, Form S-3	4-12
April 15, 1993	33-64028, Form S-3	4-13
June 15, 1993	1-1839, Form 8-K dated May 21, 1993	4-1
July 15, 1993	1-1839, Form 10-Q for quarter ended June 30, 1993.	4-1
January 15, 1994	1-1839, 1993 Form 10-K	4-15
December 1, 1994	1-1839, 1994 Form 10-K	4-16
June 1, 1996	1-1839, 1996 Form 10-K	4-16
March 1, 2002	1-1839, 2001 Form 10-K	4-4-1
May 20, 2002
June 1, 2002
October 7, 2002
January 13, 2003	1-1839, Form 8-K dated January 22, 2003	4-4
March 14, 2003	1-1839, Form 8-K dated April 7, 2003	4-4
August 13, 2003	1-1839, Form 8-K dated August 25, 2003	4-4
February 15, 2005	1-16169, Form 10-Q for the quarter ended March 31, 2005	4-3-1
February 1, 2006	1-1839, Form 8-K dated February 22, 2006	99.3
February 22, 2006	1-1839, Form 8-K dated March 6, 2006	4.1
August 1, 2006	1-1839, Form 8-K dated August 28, 2006	4.1
September 15, 2006	1-1839, Form 8-K dated October 2, 2006	4.1
December 1, 2006	1-1839, Form 8-K dated December 19, 2006	4.1

389

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, 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, 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, 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, Form 8-K dated June 9, 2005, Exhibit 99.3).
10-1	Power Purchase Agreement among Generation and PECO (Registration Statement No. 333-85496, Form S-4, Exhibit 10.1).

390

Exhibit No.	Description
10-2	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).
10-3	Exelon Corporation Deferred Compensation Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-3).
10-4	Exelon Corporation Retirement Program (File No. 1-16169, 2001 Form 10-K, Exhibit 10-4).
10-5	PECO Energy Company Unfunded Deferred Compensation Plan for Directors* (Registration Statement No. 333-49780, Form S-8, Exhibit 4-4).
10-6	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).
10-7-1	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).
10-7-2	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).
10-7-3	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).
10-8	PECO Energy Company Management Incentive Compensation Plan *(File No. 1-01401, 1997 Proxy Statement, Appendix A).
10-9	PECO Energy Company 1998 Stock Option Plan* (Registration Statement No. 333-37082, Post-Effective Amendment No. 1 to Form S-4, Exhibit 4-3).
10-10	Exelon Corporation Employee Savings Plan (File No. 1-16169, 2004 Form 10-K, Exhibit 10-13).
10-11	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).
10-12	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).
10-12-1	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).
10-12-2	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).
10-12-3	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).
10-13	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).

391

Exhibit No.	Description
10-13-1	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).
10-14	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).
10-14-1	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).
10-15	Exelon Corporation Cash Balance Pension Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-14).
10-16	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).
10-17	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).
10-18	Unicom Corporation Amended and Restated Long-Term Incentive Plan *(File No. 1-11375, Unicom Proxy Statement dated April 7, 1999, Exhibit A).
10-18-1	First Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-8).
10-18-2	Second Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-9).
10-19	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).
10-20	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).
10-21	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).
10-22	Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).
10-23	Exelon Corporation Corporate Stock Deferral Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-22).
10-24	Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12).
10-25	Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-13).

392

Exhibit No.	Description
10-26	Unicom Corporation 1996 Directors’ Fee Plan *(File No. 1-11375, Unicom Proxy Statement dated April 8, 1996, Appendix A).
10-26-1	Second Amendment to Unicom Corporation 1996 Directors Fee Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-11).
10-27	Not used.
10-27-1	First Amendment to the Commonwealth Edison Company Supplemental Management Retirement Plan * (File No. 1-1839, 2000 Form 10-K, Exhibit 10-27-1).
10-28	Amendment No. 1 to Exelon Corporation Supplemental Management Retirement Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-32).
10-29	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).
10-30	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).
10-31	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).
10-31-1	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).
10-32	Exelon Corporation Annual Incentive Plan for Senior Executives effective January 1, 2004*. (File No. 1-16169, 2004 Form 10-K, Exhibit 10-49).
10-33	Form of change in control employment agreement for senior executives newly eligible or promoted after January 1, 2004*. (File No. 1-16169, 2004 Form 10-K, Exhibit 10-50).
10-34	Form of change in control employment agreement *(amended and restated as of May 1, 2004). (File No. 1-16169, 2004 Form 10-K, Exhibit 10-51).
10-35	Amendment One to Exelon Corporation Deferred Compensation Plan*. (File No. 1-16169, 2004 Form 10-K, Exhibit 10-52).
10-36	Amendment Two to Exelon Corporation Supplemental Management Retirement Plan*. (File No. 1-16169, 2004 Form 10-K, Exhibit 10-53).
10-37	Restatement of the Exelon Corporation Employee Stock Purchase Plan, effective May 1, 2004 and Appendix One thereto. (File No. 1-16169, 2004 Form 10-K, Exhibit 10-54).
10-38	Amended and Restated Employment Agreement by and between Exelon Corporation and John W. Rowe, dated as of July 22, 2005 *(File No. 1-16169, Form 10-Q for the quarter ended June 30, 2005, Exhibit 10-2).
10-39	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).
10-40	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).

393

Exhibit No.	Description
10-41	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).
10-42	Exelon Corporation Senior Management Severance Plan (As Amended and Restated) (File No. 1-16169, 2005 Form 10-K, Exhibit 10-62).
10-43	Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated) (File No. 1-16169, 2005 Form 10-K, Exhibit 10-63).
10-44	Credit Agreement dated as of February 22, 2006 among Commonwealth Edison Company, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 1-1839, Form 8-K dated February 22, 2006, Exhibit 99.2).
10-45	One Hundred and Second Supplemental Indenture, dated as of September 15, 2006, to the First and Refunding Mortgage, dated as of May 1, 1923, between PECO Energy Company and Wachovia Bank, National Association, as trustee (File No. 000-16844, Form 8-K dated September 25, 2006, Exhibit 4.1).
10-46	Supplemental Indenture dated as of August 1, 2006 from ComEd to BNY Midwest Trust Company, as trustee, and D.G. Donovan, as co-trustee (File No. 1-1839, Form 8-K dated August 28, 2006, Exhibit 4.1).
10-47	Supplemental Indenture dated as of September 15, 2006 from ComEd to BNY Midwest Trust Company, as trustee, and D.G. Donovan, as co-trustee (File No. 1-1839, Form 8-K dated October 2, 2006, Exhibit 4.1).
10-48	Credit Agreement dated as of October 26, 2006 between Exelon Corporation and Various Financial Institutions (File No. 1-16169, Form 8-K dated October 26, 2006, Exhibit 99.1).
10-49	Credit Agreement dated as of October 26, 2006 between Exelon Generation Company and Various Financial Institutions (File No. 333-85496, Form 8-K dated October 26, 2006, Exhibit 99.2).
10-50	Credit Agreement dated as of October 26, 2006 between PECO Energy Company and Various Financial Institutions (File No. 000-16844, Form 8-K dated October 26, 2006, Exhibit 99.3).
10-51	Supplemental Indenture dated as of December 1, 2006 from ComEd to BNY Midwest Trust Company, as trustee, and D.G. Donovan, as co-trustee (File No. 1-1839, Form 8-K dated December 19, 2006, Exhibit 4.1).
10-52	Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003.
10-53	First Amendment to Exelon Corporation Executive Death Benefits Plan, effective January 1, 2006.
10-54	Amendment Number One to the Exelon Corporation 2006 Long-Term Incentive Plan, effective December 4, 2006.
10-55	Amendment Number Two to the Exelon Corporation Long-Term Incentive Plan (As Amended and Restated Effective January 28, 2002), effective December 4, 2006.
10-56	Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005).

394

Exhibit No.	Description
10-57	Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective January 1, 2005).
14	Exelon Code of Conduct.
	Subsidiaries
21-1	Exelon Corporation
21-2	Exelon Generation Company, LLC
21-3	Commonwealth Edison Company
21-4	PECO Energy Company
	Consent of Independent Registered Public Accountants
23-1	Exelon Corporation
23-2	Commonwealth Edison Company
23-3	PECO Energy Company
	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

395

Exhibit No.	Description
	Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 2006 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 John L. Skolds for Exelon Generation Company, LLC
31-4	Filed by John F. Young for Exelon Generation Company, LLC
31-5	Filed by Frank M. Clark for Commonwealth Edison Company
31-6	Filed by Robert K. McDonald for Commonwealth Edison Company
31-7	Filed by John L. Skolds for PECO Energy Company
31-8	Filed by John F. Young for PECO Energy Company
	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, 2006 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 John L. Skolds for Exelon Generation Company, LLC
32-4	Filed by John F. Young for Exelon Generation Company, LLC
32-5	Filed by Frank M. Clark for Commonwealth Edison Company
32-6	Filed by Robert K. McDonald for Commonwealth Edison Company
32-7	Filed by John L. Skolds for PECO Energy Company
32-8	Filed by John F. Young for PECO Energy Company

* Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.

396

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 13th day of February, 2007.

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 13th day of February, 2007.

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 13, 2007
Name:	John W. Rowe

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 13th day of February, 2007.

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 13th day of February, 2007.

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)

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 13th day of February, 2007.

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 13th day of February, 2006.

Signature	Title
/s/    FRANK M. CLARK	Chairman and Chief Executive Officer
Frank M. Clark	(Principal Executive Officer)
/s/    J. BARRY MITCHELL	President
J. Barry Mitchell
/s/    ROBERT K. MCDONALD         Robert K. McDonald	Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer (Principal Financial Officer)
/s/    MATTHEW R. GALVANONI         Matthew R. Galvanoni	Vice President and Controller (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 13, 2007
Name:	Frank M. Clark

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 13th day of February, 2007.

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 13th day of February, 2007.

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 R. GALVANONI         Matthew R. Galvanoni	Vice President and Controller (Principal Accounting Officer)