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Form 10-K

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, 2009

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


Commission File Number	Exact Name of Registrant as Specified in its Charter; 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 19348-2473 (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 and Chicago
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 x	No ¨
Commonwealth Edison Company	Yes x	No ¨
PECO Energy Company	Yes x	No ¨

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 ¨	No x
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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, non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


	Large Accelerated	Accelerated	Non-Accelerated	Small Reporting Company
Exelon Corporation	ü
Exelon Generation Company, LLC			ü
Commonwealth Edison Company			ü
PECO Energy Company			ü

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, 2009, was as follows:


Exelon Corporation Common Stock, without par value		$ 33,730,940,743
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 29, 2010 was as follows:


Exelon Corporation Common Stock, without par value		659,895,066
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

Documents Incorporated by Reference

Portions of the Exelon Proxy Statement for the 2010 Annual Meeting of

Shareholders are incorporated by reference in Part III.

TABLE OF CONTENTS


		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		iv
FILING FORMAT		vii
FORWARD-LOOKING STATEMENTS		vii
WHERE TO FIND MORE INFORMATION		vii

PART I
ITEM 1.	BUSINESS	1
	General	1
	Exelon Generation Company, LLC	1
	Commonwealth Edison Company	13
	PECO Energy Company	15
	Employees	19
	Environmental Regulation	20
	Executive Officers of the Registrants	25
ITEM 1A.	RISK FACTORS	29
ITEM 1B.	UNRESOLVED STAFF COMMENTS	50
ITEM 2.	PROPERTIES	50
	Exelon Generation Company, LLC	50
	Commonwealth Edison Company	52
	PECO Energy Company	52
ITEM 3.	LEGAL PROCEEDINGS	54
	Exelon Corporation	54
	Exelon Generation Company, LLC	54
	Commonwealth Edison Company	54
	PECO Energy Company	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	59
	Exelon Corporation	59
	Exelon Generation Company, LLC	60
	Commonwealth Edison Company	61
	PECO Energy Company	62
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION	63
	Exelon Corporation	63
	General	63
	Executive Overview	63
	Critical Accounting Policies and Estimates	69
	Results of Operations	81
	Liquidity and Capital Resources	106
	Exelon Generation Company, LLC	146
	Commonwealth Edison Company	148
	PECO Energy Company	150
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	131
	Exelon Corporation	131
	Exelon Generation Company, LLC	147
	Commonwealth Edison Company	149
	PECO Energy Company	151


		Page No.
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	152
	Exelon Corporation	160
	Exelon Generation Company, LLC	166
	Commonwealth Edison Company	172
	PECO Energy Company	178
	Combined Notes to Consolidated Financial Statements	184
	1. Significant Accounting Policies	184
	2. Regulatory Issues	200
	3. Accounts Receivable	212
	4. Property, Plant and Equipment	212
	5. Jointly Owned Electric Utility Plant	216
	6. Intangible Assets	217
	7. Fair Value of Financial Assets and Liabilities	219
	8. Derivative Financial Instruments	234
	9. Debt and Credit Agreements	247
	10. Income Taxes	254
	11. Asset Retirement Obligations	264
	12. Spent Nuclear Fuel Obligation	270
	13. Retirement Benefits	271
	14. Corporate Restructuring and Plant Retirements	285
	15. Preferred Securities	287
	16. Common Stock	288
	17. Earnings Per Share and Equity	296
	18. Commitments and Contingencies	296
	19. Supplemental Financial Information	316
	20. Segment Information	331
	21. Related Party Transactions	333
	22. Quarterly Data	341
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	343
ITEM 9A.	CONTROLS AND PROCEDURES	343
	Exelon Corporation	343
	Exelon Generation Company, LLC	343
	Commonwealth Edison Company	343
	PECO Energy Company	343
ITEM 9B.	OTHER INFORMATION	343
	Exelon Corporation	343
	Exelon Generation Company, LLC	343
	Commonwealth Edison Company	343
	PECO Energy Company	343


		Page No.

PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE	344
	Exelon Corporation	344
	Exelon Generation Company, LLC	344
	Commonwealth Edison Company	345
	PECO Energy Company	347
ITEM 11.	EXECUTIVE COMPENSATION	350
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	409
	Exelon Corporation	409
	Exelon Generation Company, LLC	409
	Commonwealth Edison Company	411
	PECO Energy Company	409
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	413
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	414
	Exelon Corporation	414
	Exelon Generation Company, LLC	415
	Commonwealth Edison Company	415
	PECO Energy Company	416

PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	417

SIGNATURES		442
	Exelon Corporation	442
	Exelon Generation Company, LLC	443
	Commonwealth Edison Company	444
	PECO Energy Company	445

CERTIFICATION EXHIBITS

iii

GLOSSARY OF TERMS AND ABBREVIATIONS


Exelon Corporation and Related Entities
Exelon		Exelon Corporation
Generation		Exelon Generation Company, LLC
ComEd		Commonwealth Edison Company
PECO		PECO Energy Company
BSC		Exelon Business Services Company, LLC
Exelon Corporate		Exelon’s holding company
Exelon Transmission Company		Exelon Transmission Company, LLC
Enterprises		Exelon Enterprises Company, LLC
Ventures		Exelon Ventures Company, LLC
AmerGen		AmerGen Energy Company, LLC
ComEd Funding		ComEd Funding LLC
CTFT		ComEd Transitional Funding Trust
PEC L.P.		PECO Energy Capital, L.P.
PECO Trust III		PECO Capital Trust III
PECO Trust IV		PECO Energy Capital Trust IV
PETT		PECO Energy Transition Trust
Registrants		Exelon, Generation, ComEd, and PECO, collectively

Other Terms and Abbreviations
1998 restructuring settlement		PECO’s 1998 settlement of its restructuring case mandated by the Competition Act
Act 129		Pennsylvania Act 129 of 2008
AEC		Alternative Energy Credit
AEPS Act		Pennsylvania Alternative Energy Portfolio Standards Act of 2004
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ARRA of 2009		American Recovery and Reinvestment Act of 2009
ASLB		Atomic Safety Licensing Board
Block Contracts		Forward Purchase Energy Block Contracts
CAIR		Clear Air Interstate Rule
CAMR		Federal Clear Air Mercury Rule
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980
Competition Act		Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996
CTC		Competitive Transition Charge
DOE		U.S. Department of Energy
DOJ		United States Department of Justice
DSP Program		Default Service Provider Program
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act
EROA		Expected Rate of Return on Assets
ESPP		Employee Stock Purchase Plan
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FTC		Federal Trade Commission


GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
GWh		Gigawatt Hour
HB 80		Pennsylvania House Bill No. 80
IBEW		International Brotherhood of Electrical Workers
ICC		Illinois Commerce Commission
ICE		Intercontinental Exchange
IFRS		International Financial Reporting Standards
Illinois Act		Illinois Electric Service Customer Choice and Rate Relief Law of 1997
Illinois EPA		Illinois Environmental Protection Agency
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
ISO		Independent System Operator
kV		Kilovolt
kW		Kilowatt
kWh		Kilowatt-hour
LIBOR		London Interbank Offered Rate
LILO		Lease-In, Lease-Out
LLRW		Low-Level Radioactive Waste
LTIP		Long-Term Incentive Plan
MGP		Manufactured Gas Plant
MISO		Midwest Independent Transmission System Operator, Inc.
Moody’s		Moody’s Investor Service
mmcf		Million Cubic Feet
MRV		Market-Related Value
MW		Megawatt
MWh		Megawatt hour
NAV		Net Asset Value
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
NJDEP		New Jersey Department of Environmental Protection
NOV		Notice of Violation
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission
NWPA		Nuclear Waste Policy Act of 1982
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income
PA DEP		Pennsylvania Department of Environmental Protection
PAPUC		Pennsylvania Public Utility Commission
PGC		Purchased Gas Cost Clause
PJM		PJM Interconnection, LLC
POLR		Provider of Last Resort
PPA		Power Purchase Agreement
PCCA		Pennsylvania Climate Change Act
PRP		Potentially Responsible Parties
PSEG		Public Service Enterprise Group Incorporated
PUHCA		Public Utility Holding Company Act of 1935
PURTA		Pennsylvania Public Realty Tax Act
RCRA		Resource Conservation and Recovery Act


REC		Renewable Energy Credit
RFP		Request for Proposal
RPM		PJM Reliability Pricing Model
RPS		Renewable Energy Portfolio Standards
RGGI		Regional Greenhouse Gas Initiative
RMC		Risk Management Committee
RTEP		Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
SECA		Seams Elimination Charge/Cost Adjustments/Assignment
SERP		Supplemental Employee Retirement Plan
SFC		Supplier Forward Contract
SILO		Sale-In, Lease-Out
SNF		Spent Nuclear Fuel
SSCM		Simplified Service Cost Method
TEG		Termoelectrica del Golfo
TEP		Termoelectrica Penoles
VIE		Variable Interest Entity

FILING FORMAT

This combined Form 10-K is being filed separately by Exelon, Generation, ComEd and PECO. 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 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 Bruce G. Wilson, Senior Vice President, Deputy General Counsel, and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

vii

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 additional 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 supply 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 sale of electricity and the provision of transmission and distribution services to retail 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 transmission and distribution 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.

Generation

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

Generation’s presence in well-developed wholesale energy markets, integrated hedging strategy that mitigates the adverse impact of short-term market volatility, and low-cost nuclear generating fleet that is operated consistently at high capacity factors position it well to succeed in competitive energy markets.

At December 31, 2009, Generation owned generation assets with an aggregate net capacity of 24,850 MW, including 17,009 MW of nuclear capacity. Generation controlled another 6,153 MW 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 full requirements PPA with PECO, which expires on December 31, 2010, and procurement contracts with ComEd and PECO covering a portion of their current and future electricity requirements. 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, Pennsylvania, Michigan and Ohio. Generation’s retail business is dependent upon continued deregulation of retail electric and gas markets and Generation’s ability to obtain supplies of electricity and gas at competitive prices in the wholesale market.

Generation is a public utility under the Federal Power Act, which gives the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. The FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of the utilities and set cost-based rates should the FERC find the market-based rates are not just and reasonable. 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 transmission access that enables Generation to participate in competitive wholesale markets. Matters subject to FERC jurisdiction include, but are not limited to, third-party financings, review of mergers, dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities and matters. Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC. Additionally, Generation is subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC. The promulgation of these standards has created the risk of fines and penalties being imposed by NERC and/or FERC for noncompliance. Exelon has a company-wide NERC Reliability Standards Compliance Program, which includes an employee training program, independent audits, and self assessments.

For a number of years, RTOs, such as PJM, have been formed in a number of regions to provide transmission service across multiple transmission systems. To date, PJM, the MISO, ISO-NE and Southwest Power Pool, have been approved as RTOs. 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 Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Generating Resources

At December 31, 2009, the generating resources of Generation consisted of the following:


Type of Capacity		MW
Owned generation assets ^(a)
Nuclear		17,009
Fossil ^(b)		6,189
Hydroelectric/Renewable		1,652

Owned generation assets		24,850
Long-term contracts ^(c)		6,153

Total generating resources		31,003

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

(b)	Includes 933 MW of capacity related to Units 1 and 2 at Cromby Generating Station and Units 1 and 2 Eddystone Generating station which were approved for retirement by the Exelon Board of Directors on December 1, 2009. See Plant Retirements section for further details.

(c)	Long-term contracts range in duration up to 21 years.

The owned and contracted generating resources of Generation are located in the United States in the Midwest region, which is comprised of Illinois (approximately 46% of capacity), the Mid-Atlantic region, which is comprised of Pennsylvania, New Jersey, Maryland and West Virginia (approximately 37% of capacity), the Southern region, which is comprised of Texas, Georgia and Oklahoma (approximately 16% of capacity), and the New England region, which is comprised of Massachusetts and Maine (approximately 1% of capacity).

Nuclear Facilities

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units and 17,009 MW of capacity. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2009 and 2008, electric supply (in GWh) generated from the nuclear generating facilities was 81% and 79%, respectively, of Generation’s total electric supply, which also includes fossil and hydroelectric generation and electric supply purchased for resale. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for further discussion of Generation’s electric supply sources.

AmerGen Reorganization. AmerGen, a wholly owned subsidiary of Generation through January 8, 2009, owned and operated the Clinton Nuclear Power Station (Clinton), the Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek) through that time. Effective January 8, 2009, AmerGen was merged into Generation, which now holds the operating licenses for Clinton, TMI and Oyster Creek.

Nuclear Operations. Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on Generation’s results of operations. 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 minimal environmental impact from operations and a safe operating history.

During 2009 and 2008, the nuclear generating facilities operated by Generation achieved a 93.6% and 93.9% capacity factor, respectively. Generation aggressively manages 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. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe reliable operations.

In addition to the rigorous maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. In addition, Generation has extensive safety systems in place to protect the plant, personnel and surrounding area in the unlikely event of an accident.

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 for operation of each unit. 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, 2009, show 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 Oyster Creek, which the NRC considers to be in an acceptable performance band.

Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for Peach Bottom Units 2 and 3, Dresden Units 2 and 3, Quad Cities Units 1 and 2, Oyster Creek and TMI Unit 1. The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:


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

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

(b)	Stations previously owned by ComEd.

(c)	Stations previously owned by AmerGen.

(d)	On October 28, 2004, the NRC issued the renewed operating licenses for Dresden Unit 2 and Unit 3.

(e)	Stations previously owned by PECO.

(f)	On April 8, 2009, the NRC issued the renewed operating license for Oyster Creek Unit 1.

(g)	On May 7, 2003, the NRC issued the renewed operating licenses for Peach Bottom Unit 2 and Unit 3.

(h)	On October 28, 2004, the NRC issued the renewed operating licenses for Quad Cities Unit 1 and Unit 2.

(i)	On October 22, 2009, the NRC issued the renewed operating license for Three Mile Island Unit 1.

On May 29, 2009, a coalition of citizen groups filed a Petition for Review of the NRC’s renewal of Oyster Creek’s operating license in the United States Court of Appeals for the Third Circuit. If the appeal is successful, it is unlikely that it would result in a revocation of the renewed license; however, it could cause the NRC to impose additional conditions over the course of the period of extended operation.

On August 18, 2009, PSEG submitted an application to the NRC to extend the operating licenses of Salem Units 1 and 2 by 20 years. The NRC is expected to spend a total of 22 to 30 months to review the application before making a decision.

Generation expects to apply for and obtain approval of license renewals for the remaining nuclear units. The operating license renewal process takes approximately four to five years from the commencement of the renewal process 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 original license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual and assumed renewal of operating licenses for all of Generation’s operating nuclear generating stations.

Nuclear Uprates. On June 12, 2009, in connection with the 38-MW increase in capacity at Generation’s Quad Cities nuclear plant in Illinois, Generation announced a series of planned power uprates across its nuclear fleet that will result in between 1,300 and 1,500 MW of additional generation capacity within eight years. The uprate projects represent a total expected investment of approximately $3.5 billion, as measured in current costs. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects, representing approximately one quarter of the planned uprates, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Dresden, LaSalle and Quad Cities plants in Illinois. The remainder of uprate MW will come from additional projects across Generation’s nuclear fleet beginning in 2010 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates are to be accomplished through an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the project in light of changing market conditions. The amount of expenditures to implement the plan ultimately will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

New Site Development. Generation pursues growth opportunities that are consistent with its disciplined approach to investing to maximize shareholder value, taking earnings, cash flow and financial risk into account. Generation has been exploring the development of a new nuclear plant located in Victoria County in southeast Texas; however, Generation has not made a decision to build a nuclear plant at this time. As a result of uncertainties in the domestic economy, the limited availability of Federal loan guarantees and related economic considerations, Generation announced on June 30, 2009, that it will seek an Early Site Permit (ESP) for its proposed new nuclear plant site rather than a construction and operating license as originally planned and filed with the NRC during 2008. The change in licensing strategy allows Generation to continue with some aspects of site evaluation and

approvals while deferring a decision on construction and technology choices for up to 20 years. The ESP application is on schedule to be submitted to the NRC by March 31, 2010. Additionally, Generation continues to hold options for acquiring the land. Among the various conditions that must be resolved before any formal decision is made to build a new nuclear plant by Generation are the granting of an ESP; significant progress to resolve questions around the short-term interim and long-term permanent storage, as well as potential future recycling, of SNF; broad public acceptance of a new nuclear plant; and assurances that a new plant can be financially successful, which would entail economic analysis that would incorporate assessing construction and financing costs, including the availability of sufficient financing, production and other potential tax credits, and other key economic factors. In June 2009, Exelon and Generation approved an additional $30 million of expenditures on the project, bringing total authorized spending on the project to $130 million. Amounts spent on the project through December 31, 2009 have been expensed and total approximately $97 million. The development phase of the project is expected to extend into 2010, with approval of funding beyond the $130 million commitment subject to management review and Exelon board approval.

Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities in on-site storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not 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, 2009, Generation had approximately 52,300 SNF assemblies (12,600 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 through the end of the license renewal period, and through decommissioning, until the DOE completes removing SNF from the 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		2018
Dresden		Dry cask storage in operation
LaSalle		2010
Limerick		Dry cask storage in operation
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 ^(b)		2025

(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. Dry cask storage will be in operation at those sites prior to the closing of their on-site storage pools.

(b)	The DOE previously has indicated it will begin accepting spent fuel in 2020. If this does not occur, Three Mile Island will need an onsite dry cask storage facility.

For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 12 of the Combined Notes to Consolidated Financial Statements.

As a by-product of their operations, nuclear generating units produce 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 anticipated to be operational until after 2020. 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 is currently utilizing on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its LLRW to disposal facilities in Utah and South Carolina. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Oyster Creek and Salem), and Connecticut. Due to the limited availability of LLRW disposal facilities, Generation continues to anticipate difficulties in shipping LLRW off of its sites and continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize cost impacts and on-site storage.

Nuclear Insurance. Generation is subject to liability, property damage and other risks associated with a major accidental outage at any of its nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other protection provisions. See “Nuclear Insurance” within Note 18 of the Combined Notes to Consolidated Financial Statements for details.

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 Exelon’s and 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. See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Exelon Corporation, Executive Overview; ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates, Nuclear Decommissioning Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Notes 2, 7 and 11 of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.

Dresden Unit 1, Peach Bottom Unit 1 and Zion (Zion Station), a two-unit nuclear generation station, have ceased power generation. SNF at Dresden Unit 1 is currently being stored in dry cask storage until a permanent repository under the NWPA is completed. All SNF for Peach Bottom Unit 1, which ceased operation in 1974, has been removed from the site and the SNF pool is drained and decontaminated. SNF at Zion Station is currently stored in on-site storage pools. Generation’s estimated liability to decommission Dresden Unit 1, Peach Bottom Unit 1 and Zion Station was $780 million at December 31, 2009. As of December 31, 2009, NDT funds set aside to pay for these obligations were $1,188 million.

Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, LLC (ZionSolutions) for decommissioning of Zion Station, which is located in Zion, Illinois and which ceased operation in 1998.

If the various closing conditions under the Asset Sale Agreement are satisfied and the transaction is completed, Generation will transfer to ZionSolutions substantially all of the assets (other than land)

associated with Zion Station, including assets held in NDTs (approximately $888 million as of December 31, 2009). In consideration for Generation’s transfer of those assets, ZionSolutions will assume decommissioning and other liabilities associated with Zion Station. For accounting purposes, based on agreements signed to date, the decommissioning funds are expected to continue to be recorded on Generation’s balance sheet and the transferred decommissioning obligation is expected to be replaced with a payable to ZionSolutions on Generation’s balance sheet. ZionSolutions will take possession and control of the land associated with Zion Station pursuant to a Lease Agreement with Generation, to be executed at the closing. Under the Lease Agreement, ZionSolutions will commit to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the SNF currently held in SNF pools at Zion Station. Rent payable under the Lease Agreement will be $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce any potential risk of default by EnergySolutions or ZionSolutions, EnergySolutions is required to provide a $200 million letter of credit to be used to fund decommissioning costs in case of a shortfall of decommissioning funds following specified failures of performance. EnergySolutions has also provided a performance guarantee and will enter into other agreements that will provide rights and remedies for Generation in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station. However, if the resources of EnergySolutions Inc. and its subsidiaries are inadequate to complete required decommissioning work, Generation may be required to complete the work at its own expense.

ZionSolutions and Generation will also enter into a Put Option Agreement pursuant to which ZionSolutions will have the option to transfer the remaining Zion Station assets and any associated liabilities back to Generation upon completion of all required decommissioning and other work at Zion Station. The purchase price payable under the Put Option Agreement is $1.00 plus the assumption of associated liabilities.

Completion of the transactions contemplated by the Asset Sale Agreement is subject to the satisfaction of a number of closing conditions, including the receipt of a private letter ruling from the IRS, and the approval of the license transfer from the NRC. On July 14, 2008, the IRS issued a private letter ruling indicating that the proposed transfer of the decommissioning funds would be treated as non-taxable to both Generation and EnergySolutions, and the NRC approved the license transfer request on May 4, 2009. Prior to completion of the transaction, EnergySolutions must submit a budget that demonstrates that the required work can be completed on schedule for the amount of funds held in decommissioning trusts. On October 14, 2008, EnergySolutions announced that it intended to defer the transfer of the Zion Station assets until after the financial markets stabilize and EnergySolutions reaffirms that there is sufficient value in the Zion decommissioning trust funds to ensure the success of the Zion early decommissioning project. During 2009, NDT fund balances associated with Zion Station improved to $888 million as of December 31, 2009 compared to $749 million as of December 31, 2008. Pursuant to their agreement, EnergySolutions and Generation have until December 31, 2011, to close the transaction, although the parties have rights to withdraw from the transaction before that date. Generation believes that accelerated decommissioning will make the land available for other uses earlier than originally thought possible, and can be completed cost effectively for the amounts that were collected from ratepayers and deposited into the NDT funds for Zion Station.

Fossil, Hydroelectric and Renewable Facilities

Generation operates various fossil and hydroelectric facilities and maintains ownership interests in several other facilities including LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2009 and 2008, electric supply (in GWh) generated from owned fossil and hydroelectric

generating facilities was 6% and 6%, respectively, of Generation’s total electric supply. 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 license for the Conowingo Hydroelectric Project expires on August 31, 2014 and for the Muddy Run Pumped Storage Facility Project expires on September 1, 2014. In March 2009, Generation filed a Pre-Application Document and Notice of Intent to renew the licenses, pursuant to FERC relicensing requirements. For those plants located within the control areas administered by PJM or the New England control area administered by ISO New England Inc. (ISO-NE), notice is required to be provided to PJM or ISO-NE, as applicable, before a plant can be retired.

Plant Retirements. On December 2, 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station Unit 1 and Unit 2 and Eddystone Generating Station Unit 1 and Unit 2. On January 5, 2010, PJM notified Exelon that based upon its preliminary analysis, the retirement of one or more of the Cromby and Eddystone units may result in reliability impacts to the transmission system. On February 1, 2010, Generation notified PJM that to the extent the retirement of these units results in reliability impacts, Generation would continue operations beyond its desired deactivation date during the period of construction of the necessary transmission upgrades, provided that Exelon receives the required environmental permits and adequate cost-based compensation. For more information regarding the proposed plant retirements, see Note 14 of the Combined Notes to Consolidated Financial Statements.

City Solar. On April 22, 2009, Exelon announced that it is developing a 10-MW solar power plant in Chicago, Illinois. The new plant supports Exelon’s strategy to reduce carbon emissions associated with fossil-fueled electricity generation. As of December 31, 2009, the project is approximately 82% complete and has commenced commercial operations. The project is expected to be completed by February 28, 2010. The estimated project cost is $64 million. As of December 31, 2009, total costs incurred were approximately $51 million.

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.

Long-Term Contracts

In addition to energy produced by owned generation assets, Generation sells electricity purchased under the following long-term contracts in effect as of December 31, 2009:


Seller	Location	Expiration	Capacity (MW)
Kincaid Generation, LLC	Kincaid, Illinois	2013	1,108
Tenaska Georgia Partners, LP ^(a)	Franklin, Georgia	2030	942
Tenaska Frontier, Ltd	Shiro, Texas	2020	830
Green Country Energy, LLC ^(b)	Jenks, Oklahoma	2022	795
Elwood Energy, LLC	Elwood, Illinois	2012	775
Lincoln Generating Facility, LLC	Manhattan, Illinois	2011	664
Wolf Hollow	Granbury, Texas	2023	350
Old Trail Windfarm, LLC	McLean, Illinois	2026	198
Others ^(c)	Various	2011 to 2028	491

Total			6,153

(a)	Commencing June 1, 2010 and lasting for 20 years, Generation has agreed to sell its rights to 942 MW of capacity, energy, and ancillary services supplied from its existing long-term contract with Tenaska Georgia Partners, LP through a PPA with Georgia Power, a subsidiary of Southern Company.

(b)

Commencing June 1, 2012 and lasting for 10 years, Generation has agreed to sell its rights to 520 MW, or approximately two-thirds, of capacity, energy, and ancillary services supplied from its existing long-term contract with Green Country Energy, LLC through a PPA with Public Service Company of Oklahoma, a subsidiary of American Electric Power Company, Inc.

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

Illinois Settlement Agreement

In July 2007, following extensive discussions with legislative leaders in Illinois, Generation, ComEd and other utilities and generators in Illinois reached an agreement (Illinois Settlement) with various parties concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Legislation reflecting the Illinois Settlement (Illinois Settlement Legislation) was signed into law in August 2007. Generation and ComEd committed to contributing $811 million to rate relief programs over the four-year period and partial funding for the IPA. Generation committed to contribute an aggregate of $747 million, consisting of $435 million to pay ComEd for rate relief programs for ComEd customers, $307.5 million for rate relief programs for customers of other Illinois utilities and $4.5 million for partially funding operations of the IPA. Through December 31, 2009, Generation has recognized net costs from its contributions of $727 million in the Statement of Operations of its total commitment of $747 million. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Illinois Settlement Legislation.

Fuel

The following table shows sources of electric supply in GWh for 2009 and estimated for 2010:


	Source of Electric Supply ^(a)
	2009	2010 (Est.)
Nuclear units	139,670	139,725
Purchases—non-trading portfolio	23,206	21,025
Fossil and hydroelectric units	10,189	11,674

Total supply	173,065	172,424

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

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 wholesale obligations, including to ComEd and PECO, and some of Generation’s retail business requirements.

The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2013. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2015. All of Generation’s enrichment requirements have been contracted through 2012. Contracts for fuel fabrication have been obtained through 2013. 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.

Coal is procured primarily through annual supply contracts, with the remainder supplied through either short-term contracts or spot-market purchases.

Natural gas is 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 certain commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates and Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.

Power Team

Generation’s wholesale marketing and retail electric supplier operations include the physical delivery and marketing of power obtained through its generation capacity and through 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 as part of its overall strategic growth plan, with objectives such as obtaining low-cost energy supply sources to meet its physical delivery obligations to customers and assisting customers to meet renewable portfolio standards. Power Team may buy power to meet the energy demand of its customers, including ComEd and PECO. These purchases may be 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. Where necessary, 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 in markets without an organized RTO. Generation also 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.

Power Team also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation also enters into transactions that are outside of this ratable sales plan, such as the ComEd swap which runs into 2013. However, except for the ComEd swap arrangement described below, Generation is exposed to relatively greater commodity price risk beyond 2010 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 of December 31, 2009, the percentage of expected generation hedged was 91% – 94%, 69% – 72%, and 37% – 40% for 2010, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts, including sales to ComEd and PECO to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. 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 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, 2009, Generation’s short and long-term commitments relating to the purchase and sale of energy and capacity from and to unaffiliated utilities and others were as follows:


(in millions)	Net Capacity Purchases ^(a)		Power Only Purchases ^(b)		Power Only Sales		Transmission Rights Purchases ^(c)
2010	$	305	$	91	$	1,307	$	10
2011		291		49		1,046		9
2012		274		22		568		9
2013		151		—		238		6
2014		145		—		120		—
Thereafter		1,105		—		761		—

Total	$	2,271	$	162	$	4,040	$	34

(a)

Net capacity purchases include PPAs and other capacity contracts that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2009. Expected payments include certain capacity charges which are conditional on plant availability.

(b)	Excludes renewable energy PPA contracts that are contingent in nature.

(c)	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.

On January 1, 2007, Generation began supplying a portion of ComEd’s load through staggered SFCs resulting from an ICC-approved “reverse auction” in 2006. Approximately 35% of the contracted supply from the 2006 auction was awarded to Generation. Under the terms of the auction, one-third of the contracted load expired in May 2008, another one-third expired in May 2009 and the remaining load will expire in May 2010. For the period from June 2008 to May 2009, Generation was awarded standard block energy purchase contracts with ComEd through an ICC-approved RFP. ComEd purchased the remainder of its energy load for this period on the spot market and through the existing SFCs. In addition, in order to fulfill a requirement of the Illinois Settlement to mitigate the price risk inherent in this plan, ComEd locked in a portion of the energy price through a five-year financial swap contract with Generation.

The Illinois Settlement Legislation established a new competitive process, effective June 2009, for energy procurement to be managed by the IPA, with oversight by the ICC. The IPA’s plan for ComEd’s procurement of energy from June 2009 through May 2010 was approved by the ICC in January 2009. Under the IPA’s plan, Generation will continue to supply a portion of ComEd’s energy load. See Notes 2 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

Generation has a PPA with PECO under which Generation has agreed to supply PECO with 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 will procure all of its electricity from market sources, including Generation. See PECO—Retail Electric Services, Pennsylvania Transition-Related and Regulatory Matters for additional information regarding PECO’s competitive, full-requirements energy-supply procurement process after 2010.

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 2010 are as follows:


(in millions)
Production plant	$	1,126
Nuclear fuel ^(a)		848

Total	$	1,974

(a)	Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant

ComEd

ComEd is engaged principally in the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to a diverse base of residential, commercial and industrial customers in northern Illinois. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the ICC related to distribution rates and service, the issuance of securities, and certain other aspects of ComEd’s business. ComEd is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of ComEd’s business. Specific operations of ComEd are also subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, ComEd is subject to mandatory reliability standards set by the NERC, for which Exelon has formed a company-wide NERC Reliability Standards Compliance Program.

ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of 8 million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of 3 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 2010 to 2066. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

ComEd’s kWh sales and peak electricity load are generally higher during the summer and winter months, 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 MW; its highest peak load during a winter season occurred on January 15, 2009 and was 16,328 MW.

Retail Electric Services

Under Illinois law, transmission and distribution service is regulated, while electric customers are allowed to purchase generation from a competitive electric generation supplier.

As of December 31, 2009, several competitive electric generation suppliers have been granted approval by the ICC to serve retail electricity customers in Illinois. There are currently a minimal number of residential customers being served by alternate suppliers. At December 31, 2009, approximately 53,400 retail customers (primarily commercial and industrial customers), representing approximately 52% of ComEd’s annual retail kWh sales, had elected to purchase their electricity from a competitive electric generation supplier. Customers who receive electricity from a competitive electric generation supplier continue to pay a delivery charge to ComEd.

Under Illinois law, ComEd is required to deliver electricity to all customers. ComEd’s obligation to provide fixed-price full service electric service including generation supply service, which is referred to as POLR obligations, varies by customer size. ComEd’s obligation to provide such service to residential customers and other small customers with demands of under 100 kW continues for all customers 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. ComEd does not have a fixed-price full service obligation to many of its largest customers with demands of 400 kW or greater, as this group of customers has previously been declared competitive. ComEd has full service obligations for customers with demands of 100-400 kW through May 2010. Customers with competitive declarations may still purchase power and energy from ComEd, but only at hourly market prices.

Delivery Service Rate Cases. In August 2005, ComEd filed a rate case with the ICC to comprehensively revise its tariffs and to adjust rates for delivering electricity effective January 2007. During 2006, the ICC issued various orders associated with this case, which resulted in a total annual rate increase of $83 million effective January 2007. ComEd and various other parties appealed the rate order to the courts. In September 2009, the Illinois Appellate Court affirmed the ICC’s order and denied the appeals. Several parties have asked the Appellate Court to rehear some of the rate design issues addressed in the opinion. There is no set time in which the court must act.

In October 2007, ComEd filed a rate case with the ICC for approval to increase its delivery service revenue requirement by approximately $360 million. The ICC issued an order in the rate case approving a $274 million increase in the annual revenue requirement, which became effective in September 2008. ComEd and several other parties have filed appeals of the rate order with the courts. ComEd cannot predict the timing of resolution or the results of the appeals. In the event the order is ultimately changed, the changes are expected to be prospective.

Procurement Related Proceedings. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Beginning on January 1, 2007, ComEd procured 100% of energy to meet its load service requirements through ICC-approved staggered SFCs with various suppliers, including Generation. Under the terms of the auction, one-third of the contracted load expired in May 2008, another one-third expired in May 2009 and the remaining load will expire in May 2010. For the period from June 2008 to May 2009, the ICC approved an interim plan under which ComEd procured a portion of its energy load through an RFP for standard wholesale products. ComEd

purchased the remainder of its energy load for this period on the spot market and through the existing SFCs. ComEd hedged the price of a significant portion of energy purchased on the spot market with a five-year variable to fixed financial swap contract with Generation.

Beginning in June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply. On January 7, 2009, the ICC approved the IPA’s plan for the procurement of ComEd’s expected energy requirements from June 2009 through May 2010 and a portion of ComEd’s expected energy requirements from June 2010 through May 2011. On December 28, 2009, the ICC approved the IPA’s procurement plan covering the period June 2010 through May 2015. See Notes 2 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding ComEd’s procurement-related proceedings and the financial swap contract.

Other. Illinois law provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) 30,000 or more customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. During the years 2009, 2008 and 2007, ComEd does not believe that it had any interruptions that have triggered this damage liability or reimbursement requirement.

Construction Budget

ComEd’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities, to ensure the adequate capacity and reliability of its system. Based on PJM’s RTEP, ComEd has various construction commitments, as discussed in Note 18 of the Combined Notes to Consolidated Financial Statements. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2010 is $935 million.

PECO

PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of transmission and distribution 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 is a public utility under the Pennsylvania Public Utility Code subject to 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 a public utility under the Federal Power Act subject to regulation by FERC as to transmission rates and certain other aspects of PECO’s business and by the U.S. Department of Transportation as to pipeline safety and other aspects of gas operations. Specific operations of PECO are subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, PECO is also subject to mandatory reliability standards by the NERC, for which Exelon has a company-wide NERC Reliability Standards Compliance Program.

PECO’s combined electric and natural gas retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.7 million. PECO provides electric delivery service in an area of approximately 1,900 square miles, with a population of approximately 3.7 million,

including 1.4 million in the City of Philadelphia. PECO supplies natural gas service 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 485,000 customers.

PECO has the necessary authorizations to furnish regulated electric and natural 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,” which are rights generally unlimited as to time and generally exclusive from competition from other electric and natural gas utilities. In a few defined municipalities, PECO’s natural gas service territory authorizations overlap with that of another natural gas utility but PECO does not consider those situations as posing a material competitive or financial threat.

PECO’s kWh sales and load of electricity are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating. PECO’s highest peak load occurred on August 3, 2006 and was 8,932 MW; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MW.

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

Retail Electric Services

Pennsylvania permits competition by competitive electric generation suppliers for the supply of retail electricity while transmission and distribution service remains regulated. At December 31, 2009, less than 1% of PECO’s residential and large commercial and industrial loads and 6% of its small commercial and industrial load were purchasing generation service from competitive electric generation suppliers.

Under the 1998 restructuring settlement, in accordance with the Competition Act, PECO’s electric generation rates are capped through a transition period ending December 31, 2010.

During the transition period, PECO has been authorized to recover $5.3 billion of costs that might not otherwise be recovered in a competitive market (stranded costs) with a 10.75% return on the unamortized balance through the imposition and collection of non-bypassable CTCs on customer bills. The 1998 restructuring settlement also authorized PECO to securitize up to $5 billion of its stranded cost recovery. At December 31, 2009, the unamortized balance of PECO’s stranded costs, or CTC regulatory asset, was approximately $883 million, which will be fully amortized in 2010. For 2010, PECO estimates collections of CTC revenue of $1,032 million. In 2010, to the extent the actual recoveries of CTCs differ from the authorized amount, a quarterly or monthly reconciliation adjustment to the CTC rates will be made to increase or decrease future remaining collections accordingly. The billing of CTCs will cease on December 31, 2010.

PECO has a PPA with Generation under which PECO obtains all of its electric supply from Generation through 2010. The price for this electricity is essentially equal to the energy revenues PECO is authorized to recover from customers as specified by PECO’s 1998 restructuring settlement mandated by the Competition Act.

Pennsylvania Transition-Related Legislative and Regulatory Matters. In Pennsylvania, despite the recent decline in wholesale electricity market prices, there has been some continuing interest from elected officials in mitigating the potential impact of electric generation price increases on customers

when rate caps expire. While PECO’s retail electric generation rate cap transition period does not end until December 31, 2010, transition periods have ended for seven other Pennsylvania electric distribution companies, and, in most instances, post-transition electric generation price increases occurred. In recent years, elected officials in Pennsylvania have suggested legislation to address concerns over post-transition electric generation price increases. Measures suggested by legislators include rate-increase deferrals and phase-ins, rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate-relief programs.

During 2009, PECO received PAPUC approval of its Market Rate Transition Phase-In Program and the settlement of its DSP Program. The DSP Program, which has a 29-month term beginning January 1, 2011 and ending May 31, 2013, complies with electric supply procurement guidelines set forth in Act 129 and will provide default electric service following the expiration of electric generation rate caps on December 31, 2010. In accordance with the DSP Program, PECO conducted two competitive procurements for electric supply for default electric service customers commencing January 2011. PECO has procured approximately 50% of the total estimated electric supply needed to serve the residential customer class in 2011. The results of these procurements indicate a price increase of 4%, on average, over current prices for residential customers. The actual price change will not be known until all the scheduled procurements have been completed.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Smart Meter and Energy Efficiency Programs

Smart Meter Programs. PECO is planning to spend up to approximately $650 million on its smart meter and smart grid infrastructure. On November 25, 2009, PECO filed a joint petition for partial settlement of its $550 million Smart Meter Procurement and Installation Plan with the PAPUC, which was filed on August 14, 2009 in accordance with the requirements of Act 129. On January 28, 2010, the ALJ issued an initial decision approving the partial settlement and determining remaining cost allocation issues subject to final PAPUC approval. PECO plans to file for PAPUC approval of an initial dynamic pricing and customer acceptance program in June 2010, and for approval of a universal meter deployment plan for its remaining customers in 2012.

On October 27, 2009, the DOE announced its intent to award PECO $200 million in the ARRA of 2009 matching grant funds under the Smart Grid Investment Grant Program. Assuming successful completion of the DOE negotiations and PECO’s receipt of the full award on reasonable terms, PECO is committed to implementing expanded initial deployment of 600,000 smart meters within three years and then accelerating universal smart meter deployment from 15 years to 10 years.

Energy Efficiency Programs. Pursuant to Act 129’s energy efficiency and conservation/demand (EE&C) reduction targets, PECO filed its EE&C plan with the PAPUC on July 1, 2009. On October 28, 2009, the PAPUC issued an order providing partial approval of PECO’s EE&C plan. The approved plan totals more than $330 million and includes the CFL program, weatherization programs, an energy efficiency appliance rebate and trade-in program, rebates and energy efficiency programs for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. On December 24, 2009, PECO filed revisions to the portions of the plan not approved based on PAPUC feedback.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Natural Gas

PECO’s natural gas sales and distribution revenues are derived pursuant to rates regulated by the PAPUC. PECO’s purchased natural gas cost rates, which represent a portion of total rates, are subject

to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased natural gas and the amount included in rates. In October 2008, the PAPUC approved a settlement of a gas distribution rate increase that provides for an annual revenue increase of $77 million. The approved distribution rate adjustment became effective on January 1, 2009.

PECO’s natural gas customers have the right to choose their natural gas suppliers or to purchase their gas supply from PECO at cost. Approximately 35% of PECO’s current total yearly throughput is provided by natural gas suppliers other than PECO and is related primarily to the supply of PECO’s large commercial and industrial customers. Natural gas transportation service provided to customers by PECO remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services at regulated rates.

PECO’s natural gas supply is provided by purchases from a number of suppliers for terms of up to two years. These purchases are primarily delivered under long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 46 million dekatherms. Peak natural gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 23 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 30% of PECO’s 2009-2010 heating season planned supplies.

Construction Budget

PECO’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities to ensure the adequate capacity and reliability of its system. Based on PJM’s RTEP, PECO has various construction commitments, as discussed in Note 18 of the Combined Notes to Consolidated Financial Statements. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2010 is $500 million. See ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for further information.

ComEd and PECO

Transmission Services

ComEd and PECO provide unbundled 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. 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 employees and wholesale merchant employees.

PJM is the ISO 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 energy, capacity and other 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.

ComEd’s transmission rates are established based on a formula that was approved by FERC in January 2008. FERC’s order establishes the agreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formula rate calculation on an annual basis.

ComEd’s most recent annual formula rate update filed in May 2009 reflects actual 2008 expenses and investments plus forecasted 2009 capital additions. The update resulted in a revenue requirement of $436 million resulting in an increase of approximately $6 million from the 2008 revenue requirement, plus an additional $4 million related to the 2008 true-up of actual costs. The 2009 revenue requirement of $440 million, which includes the 2008 true-up, became effective June 1, 2009 and is recovered over the period extending through May 31, 2010. The regulatory asset associated with the true-up is being amortized as the associated revenues are received. ComEd will continue to reflect its best estimate of its anticipated true-up in the financial statements.

The Competition Act, Pennsylvania’s electric utility restructuring legislation, was adopted in 1996 and unbundled electric generation, transmission and distribution services. PECO’s most recently approved bundled rate for these services was approved in 1990 and established a weighted average debt and equity return on its electric rate base of 11.23%. As a result of PECO’s 1998 restructuring settlement, retail transmission rates were capped at the level in effect on December 31, 1996. The cap expired on December 31, 2006, however those rates will continue to be in effect until PECO files a rate case or there is some other specific regulatory action to adjust retail transmission rates. PECO’s transmission rate included in the PJM Open Access Transmission Tariff is a FERC-approved rate. This is the rate that all load serving entities in the PECO transmission zone pay for transmission service. The PAPUC approves how PECO recovers this cost through its retail transmission rates.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information regarding transmission services.

Employees

As of December 31, 2009, Exelon and its subsidiaries had 19,329 employees in the following companies, of which 8,728 or 45% are covered by collective bargaining agreements (CBAs):


	IBEW Local 15 ^(a)	IBEW Local 614 ^(b)	Other CBA agreements ^(c)	Employees Covered by CBA	Total Employees
Generation	1,690	242	1,787	3,719	9,616
ComEd	3,639	—	—	3,639	5,819
PECO	—	1,254	—	1,254	2,391
Other ^(d)	89	—	27	116	1,503

Total	5,418	1,496	1,814	8,728	19,329

(a)	A separate CBA between ComEd and IBEW Local 15, ratified on November 20, 2009, covers approximately 130 employees in ComEd’s System Services Group.

(b)

1,254 PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614. The CBAs expire on March 31, 2015. Additionally, Exelon Power, an operating unit of Generation, has an agreement with IBEW Local 614, which expires on March 31, 2015 and covers 242 employees.

(c)

During 2009 and early 2010, CBAs were agreed to with the following Security Officers unions: Braidwood, Byron, Clinton, Dresden, Oyster Creek and TMI. The agreements generally expire during 2012 except for the agreements at Clinton and Oyster Creek, which expire in 2013. Additionally, during 2009, a 5-year agreement was reached with Oyster Creek Nuclear Local 1289, which will expire in 2015.

(d)	Other includes shared services employees at BSC.

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 the Registrants operate their facilities. The U.S. EPA administers certain Federal statutes relating to such matters, as do various interstate and local agencies. Various state and local environmental protection agencies or boards have jurisdiction over certain activities in states in which Exelon and its subsidiaries do business. State and local regulation includes the authority to regulate air, water and noise emissions and solid waste disposals.

The Exelon board of directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental matters, including the CEO who also serves as Exelon’s Chief Environmental Officer; the Vice President, Corporate Strategy and Exelon 2020; and the Corporate Environmental Strategy Director and the Environmental Regulatory Strategy Director, as well as senior management of Generation, ComEd and PECO. Performance for those individuals directly involved in environmental strategy activities is reviewed and affects compensation as part of the annual individual performance review process. The Exelon board has delegated to its corporate governance committee authority to oversee Exelon’s strategies and efforts to protect and improve the quality of the environment, including, but not limited to, Exelon’s climate change and sustainability policies and programs, and Exelon 2020, Exelon’s comprehensive business and environmental plan, as discussed in further detail below. The Exelon board has also delegated to its generation oversight committee authority to oversee environmental, health and safety issues relating to Generation, and to its energy delivery oversight committee authority to oversee environmental, health and safety issues related to ComEd, PECO and Exelon Transmission Company.

Water

Under the Federal Clean Water Act (Clean Water Act), NPDES permits for discharges into waterways are required to be obtained from the U.S. EPA or from the state environmental agency to which the permit program has been delegated and must be renewed periodically. All of Generation’s power generation facilities discharging industrial wastewater into waterways are subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension.

In July 2004, the U.S. 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 the impact on aquatic organisms at existing power plants and provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to this regulation. 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, Oyster Creek, Peach Bottom, Quad Cities, Salem and Schuylkill. Following legal challenges to the Phase II Rule, the Rule has been withdrawn and remanded to the U.S. EPA for revisions consistent with the courts’ decisions. In the interim, Generation has been complying with the requirements of the state permitting agencies, which are administering the Rule pursuant to their best professional judgment until a new final Rule is issued by the U.S. EPA. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would require the installation of cooling towers within seven years after the effective date of the permit. Oyster Creek will continue to operate under its current permit, issued in 1994, until the draft permit is

finalized after a period of public comment. Generation believes the public comment period and regulatory process could take up to two years before a final permit is issued. Should the permit be issued in its current form, Generation estimates it would be required to have cooling towers in operation by 2019.

Generation estimates that the cost to retrofit Oyster Creek with closed-cycle cooling towers would be approximately $700 million to $800 million. This cost estimate includes construction materials and labor, lost capacity and energy revenue during construction, and other ongoing operations and maintenance costs. Generation believes that these additional costs would call into question the economic viability of operating Oyster Creek until the expiration of its current operating license in 2029, and Generation would close Oyster Creek if either the final Section 316(b) regulations or NJDEP requirements have performance standards that require the installation of cooling towers. Closure of Oyster Creek could result in reliability issues associated with the transmission system. Generation believes the period allowed for compliance will be sufficient to address any transmission reliability issues before operations at Oyster Creek are shut down. For example, should PJM require the plant to operate under a “reliability-must-run” order, Generation would be allowed full recovery of its costs to operate until the transmission issues are resolved.

In 2005 and 2006, the Illinois EPA issued NOVs to Generation alleging violations of state groundwater standards at the Braidwood, Dresden and Byron generating stations. Exelon and Generation are in litigation with the Illinois EPA regarding these NOVs and cannot determine the outcome of these matters but believe their ultimate resolution should not, after consideration of reserves established, have a material impact on Exelon’s or Generation’s respective results of operations, cash flows or financial position. See Note 18 of the Combined Notes to Consolidated Financial Statements for discussion of NOVs received by Generation related to violations of Illinois state groundwater standards.

Generation is also subject to the jurisdiction of certain other state and regional agencies and compacts, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.

Solid and Hazardous Waste

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the U.S. 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 U.S. EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with a U.S. 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 also enacted statutes that contain provisions substantially similar to CERCLA. In addition, the 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 U.S. EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including 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 acquire MGP sites as part of the absorption of smaller utilities, for which they may be liable for environmental remediation. ComEd and PECO perform a detailed study of the MGP reserve on an annual basis and believe that appropriate reserves have been recorded. Since ComEd, pursuant to an ICC order, and PECO, pursuant to the joint settlement of the 2008 gas distribution rate case, are recovering environmental costs of remediation of the MGP sites through a provision within customer rates, future estimated recoveries are recorded as a regulatory asset. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

Costs of Environmental Remediation

At December 31, 2009, Exelon had accrued $175 million, consisting of $17 million, $113 million, and $45 million at Generation, ComEd and PECO, respectively, for various environmental investigation and remediation alternatives. Exelon has recorded a regulatory asset of $143 million, consisting of $103 million and $40 million at ComEd and PECO, respectively, related to the recovery of MGP remediation costs. See Notes 18 and 19 of the Combined Notes to Consolidated Financial Statements for additional information.

The amount to be expended in 2010 at Exelon for compliance with environmental remediation is expected to total $23 million, consisting of $1 million, $19 million and $3 million at Generation, ComEd and PECO, respectively. In addition, Generation, ComEd and PECO may be required to make significant additional expenditures not presently determinable.

Cotter Corporation

The U.S. 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. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs. Generation, which assumed ComEd’s potential liability, has accrued what it believes to be an adequate amount within the estimated cost range to cover its anticipated share of the liability. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

Air

Air quality regulations promulgated by the U.S. EPA and the various state and local environmental agencies in Illinois, Massachusetts, Pennsylvania and Texas in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO₂), nitrogen oxides (NO_x), 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, including a two-phase program to reduce acid rain effects by significantly reducing emissions of SO₂ and NO_x from power plants. Flue-gas desulfurization systems (SO₂ scrubbers) have been installed at all of Generation’s coal-fired units.

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 in past years that would reduce generating plant emissions of NO_x, SO₂, mercury and carbon. At this time, Generation can provide no assurance that new legislative and regulatory proposals, if adopted, will not have a significant effect on Generation’s operations, cash flows, or financial position.

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding national clean air legislation in the forms of the CAIR and CAMR, in addition to Keystone’s compliance with the Acid Rain Program Phase II limits and NOVs issued to Generation and ComEd for violations of the Clean Air Act.

Global Climate Change

Exelon believes the evidence of global climate change is compelling and that the energy industry, though not alone, is a significant contributor to the human-caused emissions of GHGs that many in the scientific community believe contribute to global climate change. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear and hydroelectric), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity. By virtue of its significant investment in low-carbon intensity assets, Generation’s emission intensity, or rate of carbon dioxide (CO₂) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions from the direct combustion of fossil fuels, primarily at its generating plants; CO₂, methane and nitrous oxide are all emitted in this process, with CO₂ representing the largest portion of these GHG emissions. GHG emissions from Generation’s combustion of fossil fuels represent approximately 90% of Exelon’s total GHG emissions; this is also a highly variable component of its GHG emissions to forecast due to the primarily intermediate and peaking profile of Exelon’s fossil generating fleet. However, only approximately 6% of Exelon’s total electric supply is provided by its fossil fuel generating plants. Other GHG emission sources at Exelon include natural gas (methane) leakage on the gas pipeline system and the coal piles at its generating plants, sulfur hexafluoride (SF₆) leakage in its electric operations and refrigerant leakage from its chilling and cooling equipment as well as fossil fuel combustion in its motor vehicles and usage of electricity in its facilities. Despite its small carbon footprint, Exelon believes its operations could be significantly affected by the possible physical risks of climate change and by mandatory programs to reduce GHG emissions. See Item 1A. Risk Factors for information regarding the market and financial, regulatory and legislative, and operational risks associated climate change.

See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding international, Federal, regional and state climate change legislation and regulation and its potential impact on Exelon.

Exelon’s Voluntary Climate Change Efforts. In a world increasingly concerned about global climate change, nuclear power as well as other virtually non-GHG emitting power will play a pivotal role. As a result, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon believes that the significance of its low GHG emission profile can only grow as policymakers take action to address global climate change.

Despite Exelon’s low GHG emission inventory and the absence of a mandatory national program in the United States, Exelon is actively engaged in voluntary reduction efforts. Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. Exelon made this pledge under the U.S. EPA’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. The U.S. EPA confirmed on April 6, 2009 that Exelon achieved its 2008 voluntary GHG reduction goal through its planned GHG management efforts, including the retirement of older, inefficient fossil power plants, reduced leakage of SF₆, increased use of renewable energy and its current energy efficiency initiatives. Based on its verified GHG emissions inventory, Exelon’s 2008 carbon dioxide-equivalent (CO₂-e) emissions were 9.7 million metric tons.

Compared to its 2001 baseline of 15.7 million metric tons of CO₂-e emissions, Exelon achieved a reduction of nearly 6.0 million metric tons (a 38% reduction below baseline) at the end of 2008. The cost of achieving the voluntary GHG emissions reduction goal did not have a material effect on Exelon’s results of operations, cash flows or financial position.

In 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental strategic plan. The plan, Exelon 2020, details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce Exelon’s GHG emissions and those of its customers, communities, suppliers and markets. Exelon 2020 sets a goal for Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels).

Through Exelon 2020, Exelon is pursuing three broad strategies: reducing or offsetting its own carbon footprint, helping customers and communities reduce their GHG emissions, and offering more low-carbon electricity in the marketplace. Initiatives to reduce Exelon’s own carbon footprint include reducing building energy consumption by 25%, reducing vehicle fleet emissions, improving the efficiency of the generation and delivery system for electricity and natural gas, and developing an industry-leading green supply chain. Plans to help customers reduce their GHG emissions include ComEd’s new portfolio of energy efficiency programs, a similar portfolio of energy efficiency programs at PECO to meet the requirements of the recently enacted Act 129, the implementation of smart-meters and real-time pricing programs and a broad array of communication initiatives to increase customer awareness of approaches to manage their energy consumption. See Note 2 of the Combined Notes to Consolidated Financial Statements for further information regarding ComEd and PECO smart grid filings and stimulus grant applications. Finally, Exelon will offer more low-carbon electricity in the marketplace by increasing its investment in renewable power and adding capacity to existing nuclear plants through uprates.

Exelon has incorporated Exelon 2020 into its overall business plans and has an organized implementation effort underway. This implementation effort includes a periodic review and refinement of Exelon 2020 initiatives in light of changing market conditions. Exelon has recently completed a periodic review of the original analysis of the costs and abatement potential of various emissions-reducing opportunities and remains committed to achieving the goal put forward in 2008. Specific initiatives and the amount of expenditures to implement the plan will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

FutureGen Alliance

Exelon supports efforts to develop new technologies to help reduce GHG emissions but recognizes that many opportunities to invest in new and emerging technologies are not yet commercially viable without Federal and state financial support. On January 30, 2010, Exelon announced that Generation intends to become a member of the FutureGen Alliance (FutureGen), which has been established to help fund a clean coal technology demonstration plan in Mattoon, Illinois. The proposed arrangement between Generation and FutureGen is subject to a number of conditions, including the execution of definitive agreements for participation by Generation and other contributing members. The proposed arrangement contemplates that Generation would make phased contributions of up to $32.1 million over a period of up to six years, commencing with the execution of a Cooperative Agreement between FutureGen and the DOE to provide partial funding for the project. Contributing members would have rights to withdraw from participation before a decision is made to start actual construction of the project or if there are insufficient funds to complete the project. Construction of the project is dependent on funding from contributing members, a grant of more than $1 billion from DOE, and financing from other sources.

Renewable and Alternative Energy Portfolio Standards

Thirty-three states have adopted some form of RPS requirement. As previously described, Illinois and Pennsylvania have laws specifically addressing energy efficiency and renewable energy initiatives. 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.

The Illinois Settlement Legislation required that procurement plans implemented by electric utilities include cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers by June 1, 2008, increasing to 10% by June 1, 2015, with a goal of 25% by June 1, 2025. Utilities are allowed to pass-through any costs from the procurement of these renewable resources subject to legislated rate impact criteria. ComEd procured approximately $19 million in RECs under the ICC-approved RFP for the period June 2008 through May 2009. On May 13, 2009, the ICC approved the results of an RFP to procure RECs for a total cost of $31 million for the period June 2009 through May 2010. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

The AEPS Act mandates that 1.5% to 8.0% and 4.2% to 10.0% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers shall be generated from Tier I and Tier II alternative energy resources, respectively, as measured in AECs. During 2009, PECO entered into agreements with accepted bidders, including Generation, for the purchase of 412,000 AECs annually for five years beginning no later than December 31, 2009. This agreement along with the five-year agreement entered into during 2008 for the purchase of 40,000 AECs annually were executed in accordance with its PAPUC approved plan to acquire and bank approximately 450,000 non-solar Tier I AECs annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance with the AEPS Act following the completion of its electric generation rate cap transition period.

In August 2009, the PAPUC approved a joint petition filed by PECO and various interveners for expedited approval of PECO’s early procurement and banking of up to 8,000 solar Tier 1 AECs annually for ten years. On January 25, 2010, the PAPUC approved the fixed-price agreement solar AEC procurement results. PECO plans to enter into the fixed-price agreements by February 8, 2010.

While Generation is not directly affected by RPS or AEPS legislation from a compliance perspective, increased deployment of renewable and alternative energy resources will affect regional energy markets and, at the same time, may present some opportunities for sales of Generation’s renewable power, including from Generation’s hydroelectric and landfill gas generating stations and wind energy PPAs.

See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Executive Officers of the Registrants as of February 5, 2010

Exelon


Name	Age	Position
Rowe, John W.	64	Chairman and Chief Executive Officer, Exelon; Chairman, Generation
Crane, Christopher M.	51	President and Chief Operating Officer, Exelon and Generation
Clark, Frank M.	64	Chairman and Chief Executive Officer, ComEd
O’Brien, Denis P.	49	Executive Vice President, Exelon; Chief Executive Officer and President, PECO
Gillis, Ruth Ann	55	Executive Vice President and Chief Administrative and Diversity Officer, Exelon; President, Exelon Business Services Company
McLean, Ian P.	60	Executive Vice President, Exelon and Chief Executive Officer, Exelon Transmission Company
Moler, Elizabeth A.	61	Executive Vice President, Government Affairs and Public Policy
Von Hoene Jr., William A.	56	Executive Vice President, Finance and Legal
Zopp, Andrea L.	53	Executive Vice President and General Counsel
Cornew, Kenneth W.	44	Senior Vice President, Exelon; President, Power Team division of Generation
Hilzinger, Matthew F.	46	Senior Vice President and Chief Financial Officer
DesParte, Duane M.	46	Vice President and Corporate Controller

Generation


Name	Age	Position
Rowe, John W.	64	Chairman and Chief Executive Officer, Exelon; Chairman
Crane, Christopher M.	51	President and Chief Operating Officer, Exelon and Generation
Pardee, Charles G.	50	Senior Vice President; President and Chief Nuclear Officer, Exelon Nuclear
Cornew, Kenneth W.	44	Senior Vice President, Exelon; President, Power Team
Beneby, Doyle N.	50	Senior Vice President, Exelon Generation, Acting President Exelon Power
Hilzinger, Matthew F.	46	Senior Vice President and Chief Financial Officer, Exelon (Principal Financial Officer)
Galvanoni, Matthew R.	37	Vice President and Assistant Corporate Controller, Exelon; Chief Accounting Officer (Principal Accounting Officer)

ComEd


Name	Age	Position
Clark, Frank M.	64	Chairman and Chief Executive Officer
Pramaggiore, Anne R.	51	President and Chief Operating Officer
Hooker, John T.	61	Executive Vice President, Legislative and External Affairs
Donnelly, Terence R.	49	Executive Vice President, Operations
Bradford, Darryl M.	54	Senior Vice President, Regulatory and Energy Policy and General Counsel
Butler Jr., Calvin G.	40	Senior Vice President, ComEd Corporate Affairs
Marquez, Fidel	48	Senior Vice President, Customer Operations
Trpik Jr., Joseph R.	40	Senior Vice President, Chief Financial Officer and Treasurer
Waden, Kevin J.	38	Vice President and Controller

PECO


Name	Age	Position
O’Brien, Denis P.	49	Executive Vice President, Exelon; Chief Executive Officer and President
Adams, Craig L.	57	Senior Vice President and Chief Operating Officer
Barnett, Phillip S.	46	Senior Vice President and Chief Financial Officer
Bonney, Paul R.	51	Vice President, Regulatory Affairs and General Counsel
Diaz Jr., Romulo L.	63	Vice President, Governmental and External Affairs
Acevedo, Jorge A.	38	Vice President and Controller

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

Prior to his election to his listed positions, Mr. Rowe was Chairman, Chief Executive Officer and President of Exelon from 2004 to 2008 and has served as Chairman and Chief Executive Officer of Exelon since 2002.

Prior to his election to his listed position, Mr. Crane was Executive Vice President, Exelon and Chief Operating Officer, Generation from 2007 to 2008; Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear from 2004 to 2007.

Prior to his election to his listed positions, Mr. Clark was Executive Vice President and Chief of Staff of Exelon and President of ComEd from 2004 to 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. O’Brien was President of PECO from 2003 to 2007.

Prior to her election to her listed position, Ms. Gillis was Executive Vice President, Exelon and President, Exelon Business Services Company from 2008 through 2009. Previously, she was Senior Vice President, Exelon and President, Exelon Business Services Company from 2005 to 2008; and Senior Vice President, Exelon, and Executive Vice President, ComEd from 2004 to 2005.

Prior to his election to his listed position, Mr. McLean was Executive Vice President, Finance and Markets from 2008 to 2009; and Executive Vice President, Exelon and President of the Exelon Power Team division of Generation from 2002 to 2008.

Prior to her election to her listed position, Ms. Moler was Executive Vice President, Governmental and Environmental Affairs and Public Policy from 2002 through 2009.

Prior to his election to his listed position, Mr. Von Hoene was Executive Vice President and General Counsel from 2008 to 2009; Senior Vice President and General Counsel, Exelon from 2006 to 2008; Senior Vice President and Acting General Counsel, Exelon from 2005 to 2006; and Senior Vice President and Deputy General Counsel, Exelon from 2004 to 2005.

Prior to her election to her listed position, Ms. Zopp was Executive Vice President, Exelon and Chief Human Resources Officer from 2008 through 2009; Senior Vice President, Exelon and Chief Human Resources Officer from 2007 to 2008; Senior Vice President, Human Resources, Exelon from 2006 to 2007; and Senior Vice President, General Counsel and Corporate Secretary, Sears Holding Corporation from 2003 to 2005.

Prior to his election to his listed position, Mr. Cornew held the following positions in the Power Team division of Generation: Senior Vice President, Trading and Origination from 2007 to 2008 and Senior Vice President, Power Transactions and Wholesale Marketing from 2004 to 2007.

Prior to his election to his listed position, Mr. Hilzinger was Senior Vice President, Exelon and Corporate Controller from 2005 to 2008; and Vice President, Exelon and Corporate Controller from 2002 to 2005. Mr. Hilzinger was Principal Accounting Officer for ComEd and PECO through December 31, 2006.

Prior to his election to his listed position, Mr. DesParte was Vice President, Finance of BSC from 2007 to 2008 and Vice President, Exelon Energy Delivery from 2004 to 2006.

Prior to his election to his listed position, Mr. Pardee was Senior Vice President, Generation and Chief Nuclear Officer, Exelon Nuclear from 2007 to 2008; Senior Vice President and Chief Operating Officer, Exelon Nuclear from 2005 to 2007; and Senior Vice President Engineering and Technical Services from 2004 to 2005.

Prior to his election to his listed position, Mr. Beneby was Vice President, Power Operations from 2008 to 2009; Vice President, Construction and Maintenance, PECO from 2006 to 2008; Vice President, Electric Operations, PECO from 2005 to 2006; and Vice President, Engineering and System Performance, Exelon Energy Delivery from 2004 to 2005.

Prior to his election to his listed position, Mr. Galvanoni was Vice President and Controller, ComEd and PECO from 2006 through 2009; Director of Financial Reporting and Analysis, Exelon during 2006; and Director of Accounting and Reporting, Generation from 2004 to 2005.

Prior to her election to her listed position, Ms. Pramaggiore was Executive Vice President, Customer Operations, Regulatory and External Affairs from 2007 to 2009; Senior Vice President, Regulatory and External Affairs, ComEd from 2005 to 2007; and Vice President, Regulatory and Strategic Services from 2002 to 2005.

Prior to his election to his listed position, Mr. Hooker was Senior Vice President, State Governmental Affairs and Real Estate and Facilities from 2008 to 2009; Senior Vice President, ComEd, Legislative and External Affairs from 2005 to 2008; and Senior Vice President, Exelon Energy Delivery Real Estate and Property Management from 2003 to 2005.

Prior to his election to his listed position, Mr. Donnelly was Senior Vice President, Transmission and Distribution, ComEd from 2007 through 2009; Senior Vice President, Technical Services, ComEd and PECO in 2007; and Vice President, Transmission and Substations, ComEd and PECO from 2004 through 2007.

Prior to his election to his listed position, Mr. Bradford was the Senior Vice President and General Counsel of ComEd from 2007 through June 2009; Vice President, General Counsel, ComEd from 2005 to 2007; and Vice President, Associate General Counsel, ComEd from 2003 to 2007.

Prior to his election to his listed position, Mr. Butler was Senior Vice President, Large Customer Services, State Legislative and Government Affairs, ComEd from May 2009 to January 2010; Vice President, State Legislative and Government Affairs, ComEd from 2008 to 2009; Senior Vice President, External Affairs, RR Donnelley from 2005 to 2008; and Vice President of Operations, Pontiac Division, RR Donnelley from 2004 to 2005.

Prior to his election to his listed position, Mr. Marquez was Vice President of External Affairs and Large Customer Services from 2007 to May 2009, and Vice President of External Affairs, ComEd, from 2004 to 2007.

Prior to his election to his listed position, Mr. Trpik was Vice President and Assistant Corporate Controller, Exelon, from 2004 through 2009.

Prior to his election to his listed position, Mr. Waden was Director of Accounting Operations, ComEd from 2007 through 2009; and Director of Financial Reporting and Accounting Research, Exelon Energy Delivery, LLC from 2003 through 2006.

Prior to his election to his listed position, Mr. Adams was Senior Vice President and Chief Supply Officer, BSC from 2004 to 2007.

Prior to his election to his listed position, Mr. Barnett was Senior Vice President, Corporate Financial Planning, Exelon, from 2005 to 2007; and Vice President Finance, Exelon Generation from 2003 to 2005.

Prior to his election to his listed position, Mr. Bonney was Vice President and Deputy General Counsel, Regulatory from 2001 to 2006.

Prior to his election to this listed position, Mr. Diaz was Associate General Counsel, Exelon from 2008 through 2009; City Solicitor, City of Philadelphia from 2005 through 2008; and Chair of the Commercial and Regulatory Law Group, City of Philadelphia from 2002 through 2005.

Prior to his election to his listed position, Mr. Acevedo was Assistant Controller of Generation from 2007 through July 2009; and Director of Accounting, Power Team, from 2003 through 2007.

ITEM 1A.

RISK FACTORS

Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond each Registrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the RMC, which is comprised of officers of the Registrants, to identify and evaluate the most significant risks of the Registrant’s businesses, and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Risk Oversight and Audit Committees of the Exelon Board of Directors and the ComEd and PECO Boards of Directors. In addition, the Exelon Board of Directors’ Generation Oversight and Energy Delivery Oversight Committees, respectively, evaluate risks related to the generation and energy delivery businesses. The risk factors discussed below may adversely affect one or more of the Registrants’ results of operations and cash flows and the market prices of their publicly-traded securities. Each of the Registrants has disclosed the material risks known to it to affect its business at this time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may in the future adversely affect its performance or financial condition.

The Registrants’ most significant risks arise as a consequence of: (1) Generation’s position as a predominantly nuclear generator selling power into competitive wholesale markets, and (2) the role of both ComEd and PECO as operators of electric transmission and distribution systems in two of the largest metropolitan areas in the United States. The Registrants’ major risks fall primarily under the categories of market and financial risk, regulatory and legislative risk, and operational risk.

First, Exelon and Generation have exposure to certain market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices are a function of supply and demand, which in turn are driven by factors such as the price of fuels, and in particular the price of natural gas and coal, that drive the wholesale market prices that Generation’s nuclear power plants can command, the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, and the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs.

Second, the Registrants face regulatory and legislative risks, including changes to the laws and regulations that govern competitive markets and utility cost recovery, and that drive environmental policy. In particular, Exelon’s and Generation’s financial performance may be adversely affected by changes that could affect Generation’s ability to sell the power it produces and sell into the competitive wholesale power markets at market-based prices. In addition, potential legislation regarding climate change and renewable portfolio standards could increase the pace of development of wind energy facilities, which could put downward pressure in some markets on wholesale market prices for electricity from Generation’s nuclear assets, partially offsetting any additional value Exelon and Generation could hope to derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future.

Third, the Registrants face a number of operational risks, including those risks inherent in running the nation’s largest fleet of nuclear power reactors and large electric distribution systems. The safe and effective operation of the nuclear facilities and the ability to effectively manage its associated decommissioning obligations as well as the ability to maintain the availability, reliability and safety of its energy delivery systems are fundamental to Exelon’s ability to protect and grow shareholder value.

Finally, the operating costs of ComEd and PECO and the opinions of customers and regulators of ComEd and PECO are affected by those companies’ ability to maintain the availability, reliability and safety of their energy delivery systems. A discussion of each of these risks and other risk factors is included below.

Market and Financial Risks

Generation is exposed to price fluctuations in the wholesale power market, which may negatively impact its results of operations. (Exelon and Generation)

Generation fulfills its energy supply 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 Generation’s long-term supply commitments 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 will be supplied from generating stations fueled by fossil fuels. Consequently, the open-market wholesale price of electricity likely reflects the cost of fossil fuels plus the cost to convert to electricity. Therefore, changes in the supply and cost of fossil fuels generally affect the open market wholesale price of electricity. In the event that alternative generation resources, such as wind and solar, are mandated through RPS or otherwise subsidized or encouraged through climate legislation and added to the supply, they could displace a higher cost fossil plant, which could reduce the price at which market participants sell their electricity. This could then reduce the market price at which all generators in that region, including Generation, would sell their output.

The market price for electricity is also affected by changes in the demand for electricity. Economic conditions, weather, and increases in energy efficiency and demand response can impact demand and prevent higher-cost generating resources from being called upon, effectively lowering the market price received for electricity.

The continued sluggish economy in the United States has led to reduced demand for electricity and lower prices for electricity and other commodities, which will adversely affect the Registrants’ financial condition, results of operations and cash flows. This could adversely affect the Registrants’ ability to pay dividends or fund other discretionary uses of cash such as growth projects. The weak world economy reduced the international demand for coal, oil and natural gas, and led to sharply lower fossil fuel prices putting downward pressure on electricity prices. The use of new technologies to recover natural gas from shale deposits is expected to increase natural gas supply and reserves, which will tend to place further downward pressure on natural gas prices and could reduce Generation’s revenues. A slow recovery of the economy could result in a prolonged depression of or further decline in commodity prices, which could adversely affect Exelon’s and Generation’s results of operations, cash flows and financial position.

In addition to price fluctuations, Generation is exposed to other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations. (Exelon and Generation)

Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated to purchase energy or fuel from Generation will not perform their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation might be forced to purchase or sell energy or fuel 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

Market and Financial Risks Continued

participants, which may or may not be an effective way of lessening the severity of the risk and the amounts at stake. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, the retail businesses subject Generation to credit risk through competitive electricity and natural gas supply activities that serve commercial and industrial companies. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that may be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.

Unstable Markets. The wholesale spot markets are 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 could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.

Market performance and other economic factors may decrease the value of decommissioning trust funds and benefit plan assets or increase the related obligations, which then could require significant additional funding. (Exelon, Generation, ComEd and PECO)

Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy may adversely affect the value of the investments held within Exelon’s employee benefit plan trusts and Generation’s NDTs. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts. The asset values 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 NDT fund investments may increase the funding requirements to decommission Generation’s nuclear plants. A decline in the market value of the pension and other postretirement benefit plan assets will increase the funding requirements associated with Exelon’s pension and other postretirement benefit plans. Additionally, Exelon’s pension and other postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. 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 and other postretirement benefit plans. Also, if future increases in pension and other postretirement costs as a result of reduced plan assets or other factors are not recoverable from ComEd and PECO customers, the results of operations and financial positions of ComEd and PECO could be negatively affected. Ultimately, if the Registrants are unable to successfully manage the decommissioning trust funds and benefit plan assets and obligations, their results of operations and financial positions could be negatively affected.

Disruptions in the capital and credit markets and increased volatility in commodity markets may adversely affect the Registrants’ businesses in several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets; each could adversely affect the Registrants’ financial condition, results of operations and cash flows. (Exelon, Generation, ComEd and PECO)

The Registrants rely on the capital markets, particularly for publicly-offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs if internal funds are not available from the Registrants’ respective operations. Further disruptions in the capital and credit markets, or further deterioration of the banks’ financial condition could adversely affect the Registrants’ ability to draw on their respective bank revolving credit facilities. The Registrants’ access to funds under those credit facilities is dependent on the ability of the banks that

Market and Financial Risks Continued

are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from the Registrants and other borrowers within a short period of time. Longer term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, changes to Generation’s hedging strategy to reduce collateral-posting requirements, or a reduction in dividend payments or other discretionary uses of cash.

The strength and depth of competition in competitive energy markets depends heavily on active participation by multiple trading parties, which could be adversely affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that may affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts such as the financial swap contract between Generation and ComEd as described further in Note 2 of the Combined Notes to Consolidated Financial Statements, which could have a material adverse effect on Exelon’s and Generation’s results of operations and cash flows.

If the Registrants were to experience a downgrade in their credit ratings below investment grade or otherwise fail to satisfy the credit standards of trading counterparties, they would be required to provide significant amounts of collateral under their agreements with counterparties and could experience higher borrowing costs. (Exelon, Generation, ComEd and PECO)

Generation’s trading business is subject to credit quality standards that may require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt 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. The amount of collateral required to be provided by Generation at any point in time is dependent on a variety of factors, including (1) the notional amount of trading positions, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry or Generation has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on the ratings of Generation.

ComEd’s financial swap contract with Generation and its operating agreement with PJM contain collateral provisions that are affected by its credit rating and market prices. If certain wholesale market conditions exist and ComEd were to lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required under the financial swap contract with Generation to provide collateral in the form of letters of credit or cash, which may have a material adverse effect upon its liquidity. Collateral posting by ComEd under the financial swap will generally increase as forward market prices fall and decrease as forward market prices rise. Conversely, collateral requirements under the PJM operating agreement will generally increase as market prices rise and decrease as market prices fall. Given the relationship to market prices, contract collateral requirements can be volatile. In addition, if ComEd were downgraded, it could experience higher borrowing costs as a result of the downgrade.

Market and Financial Risks Continued

PECO’s operating agreement with PJM and its natural gas procurement contracts contain collateral provisions that are affected by its credit rating. If certain wholesale market conditions exist and PECO were to lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide collateral in the form of letters of credit or cash, which may have a material adverse effect upon its liquidity. PECO’s collateral requirements relating to its natural gas supply contracts are a function of market prices. Collateral posting requirements for PECO with respect to these contracts will generally increase as forward market prices fall and decrease as forward market prices rise. Given the relationship to forward market prices, contract collateral requirements can be volatile. In addition, if PECO were downgraded, it could experience higher borrowing costs as a result of the downgrade.

Either or both ComEd and PECO could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the utility industry in general or ComEd or PECO in particular has deteriorated. ComEd or PECO could experience a downgrade if the current supportive regulatory environment in Illinois or Pennsylvania becomes less predictable by materially lowering returns for utilities in the state or adopting other measures to manage higher electricity prices. Additionally, the ratings for ComEd or PECO could be downgraded if either company’s financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have a negative impact on the ratings of ComEd or PECO.

ComEd and PECO conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that ComEd and PECO are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate ComEd and PECO from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ringfencing”) may help avoid or limit a downgrade in the credit ratings of ComEd and PECO in the event of a reduction in the credit rating of Exelon. Despite these ringfencing measures, the credit ratings of ComEd and PECO could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of ComEd or PECO, or both. A reduction in the credit rating of ComEd or PECO could have a material adverse effect on ComEd or PECO, respectively.

See Liquidity and Capital Resources—Recent Market Conditions and Security Ratings for further information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.

Results of operations may be negatively affected by increasing costs. (Exelon, Generation, ComEd and PECO)

Inflation affects the Registrants through increased operating costs and increased capital costs for plant and equipment. 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 that is higher than anticipated by the Registrants. If the Registrants are unable to successfully manage their medical benefit costs, pension costs, or other increasing costs, their results of operations could be negatively affected.

Market and Financial Risks Continued

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

Generation depends on nuclear fuel, coal, natural gas and oil to operate its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. Coal, natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, coal, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that may negatively affect the results of operations for Generation. It is not possible to accurately predict the future cost or availability of these commodities.

Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities. (Exelon and Generation)

Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading 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 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 commodity trading activities and risk management decisions may have on its business, operating results or financial position.

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. The proportion of hedged positions in its power generation portfolio may cause volatility in Generation’s future results of operations.

Generation may not be able to effectively respond to increased demand for energy. (Exelon and Generation)

Generation’s financial growth may depend in part on its ability to respond to increased demand for energy. If demand for electricity rises in the future, it may be necessary for the market to increase capacity through the construction of new generating facilities. Development by Generation of new generating facilities would require the commitment of substantial capital resources, including access to the capital markets. The wholesale markets for electricity and certain states’ statutes contemplate that future generation will be built in those markets at the risk of market participants. Thus, the ability of Generation to recover the costs of and to earn an adequate return on any future investment in generating facilities will be dependent on its ability to build, finance and efficiently operate facilities that are competitive in those markets. Additionally, 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.

Market and Financial Risks Continued

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

A significant portion of Generation’s power portfolio is used to provide power under a long-term PPA with PECO and procurement contracts with ComEd and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale market. To the extent its power portfolio is not sufficient to meet the requirements of its customers 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 its customers, manage its power portfolio and effectively handle the changes in the wholesale power markets.

Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could negatively impact the Registrants’ results of operations and cash flows. (Exelon, Generation, ComEd and PECO)

1999 sale of fossil generating assets. The IRS has challenged Exelon’s 1999 tax position on an involuntary conversion and like-kind exchange transaction. If the IRS is successful in its challenge, it would accelerate future income tax payments and increase interest expense related to the deferred tax gain that would become currently payable. As of December 31, 2009, Exelon’s and ComEd’s potential cash outflow, including tax and interest (after tax), could be as much as $1.1 billion excluding penalties. If the deferral were successfully challenged by the IRS, it could also negatively affect Exelon’s and ComEd’s results of operations by up to $300 million (after tax) related to interest expense. In addition to attempting to impose tax on the above transactions, the IRS has asserted penalties for a substantial understatement of tax, which could result in an after-tax charge of $196 million to Exelon’s and ComEd’s results of operations should the IRS prevail in asserting the penalties. The timing effects of the final resolution of this matter are unknown. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional information.

Tax reserves and the recoverability of deferred tax assets. The Registrants are required to make judgments 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 tax authorities. 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. See Notes 1 and 10 of the Combined Notes to Consolidated Financial Statements for additional information.

Increases in customer rates and the impact of economic downturns may lead to greater expense for uncollectible customer balances. Additionally, increasing rates could lead to decreased volumes delivered. Both of these factors may decrease ComEd’s and PECO’s results from operations and cash flows. (Exelon, ComEd and PECO)

ComEd’s current procurement plan includes purchasing power through contracted suppliers and the spot market. Purchased power prices fluctuate based on the supply and demand for electricity, which could lead to higher customer bills and potentially additional uncollectible accounts expense.

The cost of PECO’s purchased power, which is provided by Generation through a PPA, is capped as part of the transition period through 2010. For service following the end of PECO’s transition period, PECO will purchase power on the open market, with no return or profit to PECO, which may significantly increase the cost of power PECO procures and in turn increase costs to the customer. The increase in rates could cause customer usage to decrease, resulting in lower transmission and distribution revenues and lower profit margins for PECO.

Market and Financial Risks Continued

Gas rates charged to PECO customers are comprised primarily of purchased natural gas cost charges, which provide no return or profit to PECO, and distribution charges, which provide a return or profit to PECO. Purchased natural 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 natural gas commodity and pipeline transportation and storage services that PECO procures to service its customers. Gas rates may change quarterly based on market conditions, which may lead to higher prices and potentially additional uncollectible accounts expense. PECO’s cash flows can be affected by differences between the time period when natural gas is purchased and the ultimate recovery from customers. If purchased natural gas cost charges increase substantially reflecting higher natural gas procurement costs incurred by PECO, customer usage may decrease, resulting in lower distribution charges and lower profit margins for PECO.

In addition to increased purchased power for ComEd and PECO customers and purchased natural gas costs for PECO customers, economic downturns and the related limitations on service termination may result in an increase in the number of uncollectible customer balances, which would negatively impact ComEd’s and PECO’s results from operations and cash flows.

In accordance with PAPUC regulations, after November 30 of any year and before April 1 of the following year, an electric distribution utility or natural gas distribution utility cannot terminate service to customers with household incomes at or below 250% of the Federal poverty level. As a result, PECO may be delayed in stopping service to customers who are delinquent in their bills, which increases PECO’s uncollectible accounts expense.

The Illinois Settlement Legislation prohibits utilities from terminating electric service to an Illinois residential space-heating customer due to nonpayment, extending from December 1 of any year through March 1 of the following year. ComEd’s ability to disconnect non space-heating residential customers is also affected by certain weather restrictions, at any time of year, under the Illinois Public Utilities Act. As a result, ComEd may be delayed in stopping service to customers who are delinquent in their bills, which could increase ComEd’s uncollectible accounts expense.

The effects of weather may impact the Registrants’ results of operations and cash flows. (Exelon, Generation, ComEd and PECO)

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. Extreme weather conditions or damage resulting from 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 results of operations and cash flows.

Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. 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 commitments. Extreme weather conditions or storms may affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions can impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, 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.

Market and Financial Risks Continued

Certain long-lived assets recorded on the Registrants’ statements of financial position may become impaired, which would result in write-offs of the impaired amounts. (Exelon, Generation, ComEd and PECO)

The Registrants evaluate the carrying value of long-lived assets to be held and used for impairment whenever indications of impairment exist. The carrying value of a long-lived asset is considered impaired when the carry value is not recoverable and exceeds its fair value. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. In the event that a long-lived asset is impaired, 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, future discounted estimated cash flows or other valuation methods. Factors such as the business climate, including current energy and market conditions, and the condition of assets are considered when evaluating long-lived assets for impairment. An impairment would require Generation to reduce the long-lived asset through a charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact on Exelon’s and Generation’s results of operations.

Exelon and ComEd both had approximately $2.6 billion of goodwill recorded at December 31, 2009 in connection with the merger between PECO and Unicom Corporation, the former parent company of ComEd. Under GAAP, goodwill will remain at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off and expensed, reducing equity.

The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, ComEd’s capital structure, results of ComEd’s rate proceedings, operating and capital expenditure requirements and other factors, some not yet known. Such a potential impairment would be a noncash charge, which 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 and Note 6 of the Combined Notes to the Consolidated Financial Statements for additional discussion on goodwill impairments.

The Registrants’ businesses are capital intensive and the costs of capital projects may be significant. (Exelon, Generation, ComEd and PECO)

The Registrants’ businesses are capital intensive and require significant investments in energy generation and in other internal infrastructure projects. The Registrants’ results of operations could be adversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. See Item 1 of this Form 10-K for further information regarding the Registrants’ potential future capital expenditures.

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

The Registrants have issued certain guarantees of the performance of others, which obligate Exelon and its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by the third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on the operating results, financial condition, or cash flows of the Registrants. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

Due to its dependence on its two most 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. (Exelon and Generation)

Generation currently provides power under procurement contracts with ComEd for a significant portion of ComEd’s electricity supply requirements and a PPA with PECO to meet 100% of PECO’s electricity supply requirements through 2010. In addition, Generation entered into a financial swap contract with ComEd, effective August 2007, to hedge a portion of ComEd’s electricity supply requirements through May 2013. Consequently, Generation is highly dependent on ComEd’s and PECO’s continued payments under these procurement contracts and the PPA and would be adversely affected by negative events affecting these agreements, including the non-performance or a significant 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 competitive electric generation suppliers. (Exelon and Generation)

Because retail customers in both Illinois and Pennsylvania can switch from ComEd or PECO to a competitive electric generation supplier for their energy needs, planning to meet Generation’s obligation to provide the supply needed to serve Generation’s share of the ComEd load and to supply PECO with all of the energy PECO needs to fulfill its default service obligation is more difficult than planning for retail load before the advent of retail competition. Before retail competition, the primary variables affecting 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 from ComEd or PECO than Generation anticipates, the ComEd and/or PECO 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 ComEd and/or PECO load that Generation must serve will be lower than anticipated, which could, if market prices have decreased, cause Generation to lose opportunities in the market.

Regulatory and Legislative Risks

The Registrants’ generation and energy delivery businesses are highly regulated and could be subject to adverse legislative actions. Fundamental changes in regulation or legislation could disrupt the Registrants’ business plans and adversely affect their operations and financial results. (Exelon, Generation, ComEd and PECO)

Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation. Further, Exelon’s and Generation’s operating results and cash flows are heavily dependent upon the ability of Generation to sell power at market-based rates, as opposed to cost-based or other similarly regulated rates, and Exelon’s, ComEd’s and PECO’s operating results and cash flows are heavily dependent on their ability to recover their costs for purchased power and their costs of distribution of power to their customers. In their business planning and in the management of their operations, the Registrants must address the effects of regulation of their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, ratemaking jurisdictions and taxing authorities. Fundamental changes in regulations or other adverse legislative actions impacting the Registrants’ businesses would require changes in their business planning models and operations and could adversely affect their operating results, cash flows and the value of their assets.

Legislative and regulatory developments related to climate change and RPS may also significantly affect Exelon’s and Generation’s operating results, cash flows and the value of their assets. Various

Regulatory and Legislative Risks Continued

proposals for climate legislation and GHG regulation, if enacted into law, could result in increased costs to entities that generate electricity through carbon-emitting fossil fuels, which could increase the market price at which all generators in that region, including Generation, may sell their output, thereby increasing the revenue Generation could realize from its low-carbon nuclear assets. However, legislation regarding climate change and RPS could also increase the pace of development of wind energy facilities in the Midwest, which could put downward pressure on wholesale market prices for electricity from Generation’s Midwest nuclear assets, partially offsetting any additional value Exelon and Generation could hope to derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future. The Registrants cannot predict when or whether any of these various legislative and regulatory proposals may become law or what their effect will be on the Registrants.

Generation may be negatively affected by possible Federal legislative or regulatory actions that could affect the scope and functioning of the wholesale markets. (Exelon and Generation)

Federal and state legislative and regulatory bodies are facing pressures to address consumer concerns that energy prices in wholesale markets exceed the marginal cost of operating nuclear plants, claims that this difference is evidence that the competitive model is not working, and resulting calls for some form of re-regulation, the elimination of marginal pricing, the imposition of a generation tax, or some other means of reducing the earnings of Generation and its competitors. As the energy markets continue to mature, a low number of wholesale market power participants entering procurement proceedings may also influence how certain regulators and legislators view the effectiveness of these competitive markets.

The criticism of restructured electricity markets, which has escalated in recent years as retail rate freezes expired and prices of electricity increased with rising fuel prices, is expected to continue in 2010. A number of advocacy groups have urged FERC to reconsider its support of competitive wholesale electricity markets and require the RTOs to revise the rules governing the RTO-administered markets. 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, and to purchase power to meet obligations not provided by its own resources. These wholesale markets allow Generation to take advantage of market price opportunities but also expose Generation to market risk.

Wholesale markets have only been implemented in certain areas of the country and each market has unique features, which may create trading barriers between the markets. Approximately 80% 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 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) the absence of material changes to market structures that would limit or otherwise negatively affect the competitiveness of the PJM market, such as, for example, withdrawal of significant participants from the regional wholesale markets. Generation could also be adversely affected by efforts of state legislatures and regulatory authorities to respond to the concerns of consumers or others about the costs of energy that are reflected through wholesale markets.

In particular, the advocacy groups oppose the RTOs’ use of a “single clearing price” for electricity sold in the RTO markets utilizing locational marginal pricing. FERC conducted conferences which led to a rulemaking on Wholesale Competition in Regions with Organized Electric Markets. On October 17,

Regulatory and Legislative Risks Continued

2008, FERC issued a Final Rule, Order No. 719, to improve the operation of organized wholesale electric markets in the areas of (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market-monitoring policies; and (4) the responsiveness of RTOs and ISOs. A number of entities have filed requests for rehearing with FERC. The outcome of this FERC rulemaking process could significantly affect Generation’s results of operations, financial position and cash flows.

In addition, on June 21, 2007, FERC issued a Final Rule on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities. FERC provided clarification to the Final Rule on December 14, 2007. The Final Rule made a number of changes in FERC’s market-based rate analysis and required several market power update filings by Generation, ComEd and PECO, the first of which was made on January 14, 2008. As discussed in more detail in Note 2 of the Combined Notes to Consolidated Financial Statements, during 2009, FERC issued three orders accepting Exelon’s filings, and therefore affirmed that Exelon’s affiliates with market-based rates can continue to make market-based sales. Accordingly, the application of the Final Rule has not had and is not currently expected to have a material adverse effect on Exelon’s and Generation’s results of operations, although the longer term impact will depend on how FERC applies the Final Rule as its enforcement of the rule matures with time and experience.

Currently, legislation under consideration in Congress and rulemakings under consideration by the Commodity Futures Trading Commission would require over-the-counter derivative products to be moved to exchanges or be centrally cleared. Power Team currently has substantial unsecured credit with various counterparties available for over-the-counter derivative transactions that could require Generation, or its counterparties, to post additional collateral if they were moved to an exchange or centrally cleared. These rule changes could reduce overall market liquidity and participation, which is a threat to the competitive market model. In addition, these changes could significantly affect Generation’s cash flows.

Generation’s affiliation with ComEd and PECO, together with the presence of a substantial percentage of Generation’s physical asset base within the ComEd and PECO service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding ComEd and/or PECO retail rates result in settlements or legislative or regulatory requirements funded in part by Generation. (Exelon and Generation)

Generation has significant generating resources within the service areas of ComEd and PECO and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation’s affiliation with ComEd and PECO and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of energy production and supply, those officials and advocacy groups may question or challenge costs incurred by ComEd or PECO, including transactions between Generation, on the one hand, and ComEd or PECO, on the other hand, regardless of any previous regulatory processes or approvals underlying those transactions. The prospect of such challenges may increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges may subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators may seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes and contributions to rate-relief packages.

Regulatory and Legislative Risks Continued

Legislators or regulators may respond to anticipated increases in rates following the end of the retail electric generation rate cap transition period in Pennsylvania on December 31, 2010 by enacting laws or regulations aimed at restricting or controlling those rates or by establishing rate relief programs that could require significant funding from PECO and/or Generation that could adversely affect PECO and/or Generation’s results of operations. (Exelon, Generation and PECO)

In Pennsylvania, there has been some continuing interest from legislators and regulators in mitigating the potential impact of electric generation price increases on customers when rate caps expire. Although Act 129 provides guidelines associated with electricity procurement that support competitive, market-based procurement, elected officials have suggested rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate-relief programs. PECO and Generation cannot predict whether any of these measures will become law or whether elected officials or regulators might take action that could have a material impact on the procurement process. If the price that PECO is allowed to bill to customers for electricity is below PECO’s cost to procure and deliver electricity, PECO expects that it will suffer adverse consequences, which could be material.

The Illinois Settlement Legislation enacted in 2007 providing rate relief to Illinois electric customers and requiring other changes in the electric industry in lieu of harmful alternatives such as rate freezes, caps, or a tax on generation, could be reversed or modified by new legislation that could be harmful to ComEd and Generation. (Exelon, Generation and ComEd)

The Illinois Settlement Legislation enacted in 2007 reflects the Illinois Settlement reached by ComEd, Generation, and other utilities and generators in Illinois with various parties concluding discussions of measures to address higher electric bills experienced in Illinois since the end of the legislatively mandated transition and rate freeze at the end of 2006. The Illinois Settlement Legislation addressed those concerns without implementing a rate freeze, generation tax, or other alternative measures that Exelon believes would have been harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. For more information regarding potential risks associated with such legislation, see “Illinois Settlement Agreement” and “Retail Electric Services” in ITEM 1 of this Form 10-K. Although the Illinois Settlement Legislation allows the contributors to the rate relief to terminate their funding commitments and recover any undisbursed funds set aside for rate relief in the event that, prior to August 1, 2011, the Illinois General Assembly passes legislation that freezes or reduces electric rates of or imposes a generation tax on parties to the Illinois Settlement, there is no guarantee that such legislation will not be passed and enacted in Illinois. The experience in Illinois in 2007 suggests a risk that the Illinois General Assembly may threaten extreme measures again in the future in an attempt to force electric utilities and generators to make further concessions. Such legislation, if enacted, could have a material adverse effect on ComEd and Generation’s results of operations, financial position, and cash flows.

The Registrants may incur substantial costs to fulfill their obligations related to environmental and other matters. (Exelon, Generation, ComEd and PECO)

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 remediation of environmental contamination of

Regulatory and Legislative Risks Continued

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.

If application of the Section 316(b) of the Clean Water Act regulations establishing a national requirement for reducing the adverse impacts to 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. The amount of the costs required to retrofit Oyster Creek may also negatively impact Generation’s decision to operate the plant after the Section 316(b) of the Clean Water Act matter is ultimately resolved. Additionally, 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 make a material contribution to a fund 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. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information.

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. (Exelon, ComEd and PECO)

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 that may not be limited by statute. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for ComEd or PECO to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates can be adjusted, including rates for the procurement of electricity or gas and the recovery of costs related to MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.

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

ComEd and PECO cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania or Federal regulators for establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that ComEd and PECO will continue to be obligated to

Regulatory and Legislative Risks Continued

deliver electricity to customers in their respective service territories and will also retain significant POLR and default service obligations to provide electricity service to certain groups of 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.

Federal or additional state RPS and/or energy conservation legislation along with energy conservation by customers could negatively affect the results of operations and cash flows of ComEd and PECO. (Exelon, ComEd and PECO)

Changes to current state legislation or the development of Federal legislation that requires the use of renewable and alternate fuel sources, such as wind, solar, biomass and geothermal, could significantly impact ComEd and PECO, especially if timely cost recovery is not allowed. The impact could include increased costs for RECs and purchased power.

Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, will increase capital expenditures and could significantly impact ComEd and PECO if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, ComEd and PECO. For additional information, see ITEM 1. Business “Environmental Regulation-Renewable and Alternative Energy Portfolio Standards”.

ComEd and PECO are likely to be subject to higher transmission operating costs in the future as a result of PJM’s RTEP. (Exelon, ComEd and PECO)

In accordance with a FERC order and related settlement, PJM’s RTEP requires the costs of new transmission facilities to be allocated across the entire PJM footprint for new facilities greater than or equal to 500 kV, and requires costs of new facilities less than 500 kV to be allocated to the beneficiaries of the new facilities. On August 6, 2009, the U.S. Court of Appeals for the Seventh Circuit remanded to FERC its decision related to allocation of new facilities 500 kV and above for further proceedings. ComEd and PECO cannot estimate the longer-term impact on their respective results of operations and cash flows because of the uncertainties relating to what new facilities will be built, the cost of building those facilities and the allocation ultimately determined by further proceedings. See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional information.

The impact of not meeting the criteria of the authoritative guidance for accounting for the effects of certain types of regulation could be material to Exelon, ComEd and PECO. (Exelon, ComEd and PECO)

As of December 31, 2009, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria of the authoritative guidance for accounting for the effects of certain types of regulation. 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. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements of Exelon, ComEd and PECO. At

Regulatory and Legislative Risks Continued

December 31, 2009, the extraordinary gain could have been as much as $1.7 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2009, the extraordinary charge could have been as much as $1.5 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. Exelon would record an extraordinary gain or charge in an equal amount related to ComEd’s and PECO’s regulatory assets and liabilities in addition to a charge against OCI (before taxes) of up to $2.5 billion and $92 million for ComEd and PECO, respectively, 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 could be significant and at least partially offset the extraordinary gain discussed above. A significant decrease in equity as a result of any changes could limit the ability of ComEd and PECO to pay dividends under Federal and state law and cause significant volatility in future results of operations. See Notes 1, 2, 6 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.

Exelon and Generation may incur material costs of compliance if Federal and/or state legislation is adopted to address climate change. (Exelon and Generation)

Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. Select Northeast and Mid-Atlantic states have developed a model rule, via the RGGI, to regulate CO₂ emissions from fossil-fired generation in participating states starting in 2009. Federal and/or state legislation to reduce GHG emissions is likely to evolve in the future. If these plans become effective, Exelon and Generation may incur material costs either to additionally limit the GHG emissions from their operations or to procure emission allowance credits. The nature and extent of environmental regulation may also impact the ability of Exelon and its subsidiaries to meet the GHG emission reduction targets of Exelon 2020. For example, more stringent permitting requirements may preclude the construction of lower-carbon nuclear and gas-fired power plants. Similarly, a Federal RPS could increase the cost of compliance by mandating the purchase or construction of more expensive supply alternatives. For more information regarding climate change, see “Global Climate Change” in ITEM 1 of this Form 10-K.

The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards. (Exelon, Generation, ComEd and PECO)

As a result of the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including Generation, ComEd and PECO, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with or changes in the 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, respectively. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.

The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could have a material adverse effect on their results of operations, financial positions and cash flows. (Exelon, Generation, ComEd and PECO)

The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of which are summarized in Note 18 of the Combined Notes to Consolidated Financial Statements.

Operational Risks

The Registrants’ employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of the energy industry. (Exelon, Generation, ComEd and PECO)

Employees and contractors throughout the organization work in, and customers and the general public may be exposed to, potentially dangerous environments near operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life. Significant risks include nuclear accidents, dam failure, gas explosions, pole strikes and electric contact cases.

War, acts and threats of terrorism, natural disaster, pandemic and other significant events may adversely affect Exelon’s results of operations, its ability to raise capital and its future growth. (Exelon, Generation, ComEd and PECO)

Exelon does not know the impact that any future terrorist attacks may have on the industry in general and on Exelon in particular. In addition, any retaliatory military strikes or sustained military campaign may affect its operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. The possibility alone that infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities, 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, natural disasters and other events that have an adverse effect on the economy in general may adversely affect Exelon’s operations and its ability to raise capital. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also may affect Exelon’s results of operations and its ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.

The United States is currently in a pandemic situation related to the H1N1 virus, but the impact to Exelon is expected to be negligible if there is no change to the current severity of the pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate its generating and transmission and distribution assets could be affected, resulting in decreased service levels and 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.

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

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 produce additional energy from primarily its fossil 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 produce energy from its nuclear stations.

Operational Risks Continued

Nuclear refueling outages. Refueling outages are planned to occur once every 18 to 24 months and currently average approximately 24 days in duration for the nuclear plants operated by Generation. The total number of refueling outages, along with their duration, can have a significant impact on Generation’s results of operations. 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%.

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 previously had a limited number of fuel performance issues. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities. It is difficult to predict the cost for unknown potential future issues and any required remediation actions.

Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, 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 SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs. 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. Any regulatory action relating to the timing and availability of a repository for SNF may adversely affect Generation’s ability to fully decommission its nuclear units.

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, impairment charges and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. In addition, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments.

Should a national policy for the disposal of SNF not be developed, the unavailability of a repository for SNF 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.

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

Operational Risks Continued

to happen, identifying and correcting the causes may require significant time and expense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners. For the plant not wholly owned by Generation and operated by PSEG, Salem Units 1 and 2, from which Generation receives its share of the plant’s output, Generation’s results of operations are dependent on the operational performance of the co-owner operators and could be adversely affected by a significant event at those plants. Additionally, continued poor operating performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affect Generation’s results of operations or financial position. In addition, closure of generating plants owned by others, or extended interruptions of their operations, could have effects on transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.

Nuclear major incident risk. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident can be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned by Generation or owned by others, may exceed Generation’s resources, including insurance coverage. Additionally, an accident or other significant event at a nuclear plant within the United States, owned by others or Generation, may result in increased regulation and reduced public support for nuclear-fueled energy 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. As of January 1, 2010, the required amount of nuclear liability insurance is $375 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 $12.6 billion limit for a single incident.

Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. In recent years, NEIL has made distributions to its members. NEIL did not make a distribution in 2009, and 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 units that have been retired) addressing Generation’s ability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on the decommissioning trust funds. The NRC funding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit.

Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results may differ significantly from current estimates. The performance of capital markets also can significantly affect the value of the trust funds. Currently, Generation is making contributions to the trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from ComEd customers or from the

Operational Risks Continued

previous owners of Clinton, TMI Unit No. 1 and Oyster Creek generating stations, if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation were unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units may be negatively affected. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

Ultimately, if the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Generation’s cash flows and financial position may be significantly adversely affected. See Note 11 of the Combined Notes to Consolidated Financial Statements for additional information.

Generation’s financial performance may be negatively affected by risks arising from its ownership and operation of hydroelectric facilities. (Exelon and Generation)

Hydroelectric plants are licensed by FERC. The license for the Conowingo Hydroelectric Project expires August 31, 2014, and the license for the Muddy Run Pumped Storage Project expires on September 1, 2014. Generation cannot predict whether it will receive all the regulatory approvals for the renewed license of its hydroelectric facilities. If FERC does not renew the operating licenses for Generation’s hydroelectric facilities 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, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation may also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions may be imposed as part of the license renewal process that may adversely affect operations, may require a substantial increase in capital expenditures or may result in increased operating costs and significantly affect Generation’s results of operations or financial position. Similar effects may result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.

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. (Exelon, ComEd and PECO)

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. Equipment or facilities failures can be due to a number of factors, including weather. Those failures or those of other utilities, including prolonged or repeated failures, can affect customer satisfaction and 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 some circumstances involving extended outages affecting large numbers of its customers.

Operational Risks Continued

The physical risks associated with climate change could impact the Registrant’s results of operations and cash flows. (Exelon, ComEd and PECO)

Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena, could affect some, or all, of the Registrant’s operations. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for Exelon’s and Generation’s continued operation, particularly the cooling of generating units.

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

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.

Failure to attract and retain an appropriately qualified workforce may negatively impact the Registrants’ results of operations. (Exelon, Generation, ComEd and PECO)

Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, may lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. If the Registrants are unable to successfully attract and retain an appropriately qualified workforce, their results of operations could be negatively affected.

The Registrants are subject to information security risks. (Exelon, Generation, ComEd and PECO)

A security breach of the Registrants’ information systems could impact the reliability of the generation fleet and/or reliability of the transmission and distribution system or subject them to financial harm associated with theft or inappropriate release of certain types of information. The Registrants cannot accurately assess the probability that a security breach may occur, despite the measures taken by the Registrants to prevent such a breach, and are unable to quantify the potential impact of such an event.

Due to PECO’s dependence on Generation to fulfill 100% of its electric energy supply requirements under a PPA, PECO could be negatively affected in the event of Generation’s inability to perform under the PPA. (Exelon and PECO)

PECO currently acquires 100% of its electric energy and capacity requirements under a PPA with Generation. In accordance with the PPA, the current electric generation rates that PECO pays have been fixed and will continue to be fixed through 2010. In the event that Generation could not perform under the PPA, PECO would be forced to purchase electric energy from alternative sources at potentially higher rates. While PECO believes that this event is unlikely to occur, such an event could have a negative impact on PECO’s results of operations and financial position.

The Registrants may make acquisitions that do not achieve the intended financial results. (Exelon, Generation, ComEd and PECO)

The Registrants may make investments and pursue mergers and acquisitions that fit their strategic objectives and improve their financial performance. It is possible that FERC or state public utility commission regulations may impose certain other restrictions on such transactions. 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, 2009:

Station

Location

No. of
Units

Percent
Owned ^(a)

Primary
Fuel Type

Primary
Dispatch
Type ^(b)

Net
Generation
Capacity (MW) ^(c)

Nuclear ^(d)

Braidwood

Braidwood, IL

Uranium

Base-load

2,360

Byron

Byron, IL

Uranium

Base-load

2,336

Clinton

Clinton, IL

Uranium

Base-load

1,065

Dresden

Morris, IL

Uranium

Base-load

1,740

LaSalle

Seneca, IL

Uranium

Base-load

2,288

Limerick

Limerick Twp., PA

Uranium

Base-load

2,293

Oyster Creek

Forked River, NJ

Uranium

Base-load

625

Peach Bottom

Peach Bottom Twp., PA

Uranium

Base-load

1,145

^(e)

Quad Cities

Cordova, IL

Uranium

Base-load

1,317

^(e)

Salem

Hancock’s Bridge, NJ

42.59

Uranium

Base-load

1,003

^(e)

Three Mile Island

Londonderry Twp, PA

Uranium

Base-load

837

17,009

Fossil (Steam Turbines)

Conemaugh

New Florence, PA

20.72

Coal

Base-load

352

^(e)

Cromby 1

Phoenixville, PA

Coal

Intermediate

144

^(f)

Cromby 2

Phoenixville, PA

Oil/Gas

Intermediate

201

^(f)

Eddystone 1, 2

Eddystone, PA

Coal

Intermediate

588

^(f)

Eddystone 3, 4

Eddystone, PA

Oil/Gas

Intermediate

760

Fairless Hills

Falls Twp, PA

Landfill Gas

Peaking

Handley 4, 5

Fort Worth, TX

Gas

Peaking

870

Handley 3

Fort Worth, TX

Gas

Intermediate

395

Keystone

Shelocta, PA

20.99

Coal

Base-load

357

^(e)

Mountain
Creek 6, 7

Dallas, TX

Gas

Peaking

240

Mountain Creek 8

Dallas, TX

Gas

Intermediate

565

Schuylkill

Philadelphia, PA

Oil

Peaking

166

Wyman

Yarmouth, ME

5.89

Oil

Intermediate

^(e)

4,734

Station

Location

No. of
Units

Percent
Owned ^(a)

Primary
Fuel Type

Primary
Dispatch
Type ^(b)

Net
Generation
Capacity (MW) ^(c)

Fossil (Combustion Turbines)

Chester

Chester, PA

Oil

Peaking

Croydon

Bristol Twp., PA

Oil

Peaking

391

Delaware

Philadelphia, PA

Oil

Peaking

Eddystone

Eddystone, PA

Oil

Peaking

Falls

Falls Twp., PA

Oil

Peaking

Framingham

Framingham, MA

Oil

Peaking

LaPorte

Laporte, TX

Gas

Peaking

152

Medway

West Medway, MA

Oil/Gas

Peaking

105

Moser

Lower Pottsgrove Twp., PA

Oil

Peaking

New Boston

South Boston, MA

Oil

Peaking

Pennsbury

Falls Twp., PA

Landfill Gas

Peaking

Richmond

Philadelphia, PA

Oil

Peaking

Salem

Hancock’s Bridge, NJ

42.59

Oil

Peaking

^(e)

Schuylkill

Philadelphia, PA

Oil

Peaking

Southeast Chicago

Chicago, IL

Gas

Peaking

296

Southwark

Philadelphia, PA

Oil

Peaking

1,442

Fossil (Internal Combustion/Diesel)

Conemaugh

New Florence, PA

20.72

Oil

Peaking

^(e)

Cromby

Phoenixville, PA

Oil

Peaking

Delaware

Philadelphia, PA

Oil

Peaking

Keystone

Shelocta, PA

20.99

Oil

Peaking

^(e)

Schuylkill

Philadelphia, PA

Oil

Peaking

Hydroelectric and Renewable

City Solar

Chicago, IL

n.a.

Solar

Base-load

^(g)

Conowingo

Harford Co., MD

Hydroelectric

Base-load

572

Muddy Run

Lancaster, PA

Hydroelectric

Intermediate

1,070

1,652

Total

124

24,850

(a)	100%, unless otherwise indicated.

(b)

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 lower-efficiency, quick response steam units, gas turbines, diesels and pumped-storage hydroelectric equipment normally used during the maximum load periods.

(c)	For nuclear stations capacity reflects the annual mean rating. All other stations reflect a summer rating.

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

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

(f)

On December 2, 2009, Generation announced its intention to permanently retire four of its fossil-fired generating units effective May 31, 2011. Eddystone Generating Station Unit1 and Unit 2 and Cromby Generating Station Unit 1 are coal-fired units and Cromby Generating Station Unit 2 operates on either natural gas or fuel oil.

(g)	Table represents total expected capacity upon project completion. City Solar is 82% complete as of December 31, 2009.

The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies 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 policy 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

ComEd’s electric substations and a portion of its transmission rights of way are located on property that ComEd owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ComEd believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements, licenses and franchise rights; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

Transmission and Distribution

ComEd’s higher voltage electric transmission lines owned and in service at December 31, 2009 were as follows:

ComEd’s electric distribution system includes 34,872 circuit miles of overhead lines and 29,765 cable miles of underground lines.

First Mortgage and Insurance

The principal 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.

ComEd maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd is 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.

PECO

PECO’s electric substations and a portion of its transmission rights of way are located on property that PECO owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

Transmission and Distribution

PECO’s higher voltage electric transmission lines owned and in service at December 31, 2009 were as follows:

(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.

PECO’s electric distribution system includes 12,971 circuit miles of overhead lines and 15,788 cable miles of underground lines.

Gas

The following table sets forth PECO’s natural gas pipeline miles at December 31, 2009:


		Pipeline Miles
Transportation		31
Distribution		6,703
Service piping		5,707

Total		12,441

PECO has an LNG facility located in West Conshohocken, Pennsylvania that 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.

First Mortgage and Insurance

The principal 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 and refunding mortgage bonds are issued.

PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is 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 PECO.

Exelon

Security Measures

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 has strategic relationships 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.

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 2 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.

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 29, 2010, there were 659,895,066 shares of common stock outstanding and approximately 135,286 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:


	2009								2008
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	51.98	$	54.47	$	51.46	$	58.98	$	63.84	$	92.13	$	91.84	$	87.25
Low price		45.90		47.30		44.24		38.41		41.23		60.00		81.00		70.00
Close		48.87		49.62		50.12		45.39		55.61		62.62		89.96		81.27
Dividends		0.525		0.525		0.525		0.525		0.525		0.500		0.500		0.500

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 2005 through 2009.

This performance chart assumes:

•

$100 invested on December 31, 2004 in Exelon Corporation common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and

•

All dividends are reinvested.

LOGO

Generation

As of January 29, 2010, Exelon held the entire membership interest in Generation.

ComEd

As of January 29, 2010, there were 127,016,519 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 29, 2010, in addition to Exelon, there were 252 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

PECO

As of January 29, 2010, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly 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.

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.

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 III 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 ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.

At December 31, 2009, Exelon had retained earnings of $8,134 million, including Generation’s undistributed earnings of $2,169 million, ComEd’s retained earnings of $304 million consisting of retained earnings appropriated for future dividends of $1,943 million, partially offset by $1,639 million of unappropriated retained deficits and PECO’s retained earnings of $426 million.

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2009 and 2008:


	2009								2008
(per share)	4^th Quarter		3^rd Quarter		2^nd Quarter		1^stQuarter		4^th Quarter		3^rd Quarter		2^nd Quarter		1^st Quarter
Exelon	$	0.525	$	0.525	$	0.525	$	0.525	$	0.525	$	0.500	$	0.500	$	0.500

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


	2009								2008^(a)
(in millions)	4^thQuarter		3^rdQuarter		2^ndQuarter		1^stQuarter		4^thQuarter		3^rdQuarter		2^nd Quarter		1^stQuarter
Generation	$	475	$	1,126	$	396	$	279	$	301	$	253	$	302	$	689
ComEd		60		60		60		60		—		—		—		—
PECO		65		93		67		87		98		146		97		139

(a)	During 2008, ComEd did not pay a dividend in order to manage cash flows and its capital structure.

On January 26, 2010, the Exelon Board of Directors declared a regular quarterly dividend of $0.525 per share on Exelon’s common stock. The dividend is payable on March 10, 2010, to shareholders of record of Exelon at the end of the day on February 16, 2010.

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 Operations included in ITEM 7 of this Report on Form 10-K.


	For the Years Ended December 31,
in millions, except for per share data	2009		2008		2007		2006		2005
Statement of Operations data:
Operating revenues	$	17,318	$	18,859	$	18,916	$	15,655	$	15,357
Operating income		4,750		5,299		4,668		3,521		2,724
Income from continuing operations	$	2,706	$	2,717	$	2,726	$	1,590	$	951
Income (loss) from discontinued operations		1		20		10		2		14
Income before cumulative effect of changes in accounting principles		2,707		2,737		2,736		1,592		965
Cumulative effect of changes in accounting principles (net of income taxes)		—		—		—		—		(42	)

Net income ^(a)	$	2,707	$	2,737	$	2,736	$	1,592	$	923

Earnings per average common share (diluted):
Income from continuing operations	$	4.09	$	4.10	$	4.03	$	2.35	$	1.40
Income (loss) from discontinued operations		—		0.03		0.02		—		0.02
Cumulative effect of changes in accounting principles (net of income taxes)		—		—		—		—		(0.06	)

Net income	$	4.09	$	4.13	$	4.05	$	2.35	$	1.36

Dividends per common share	$	2.10	$	2.03	$	1.76	$	1.60	$	1.60

Average shares of common stock outstanding—diluted		662		662		676		676		676

(a)	The changes between 2007 and 2006; and 2006 and 2005 were primarily due to the impact of the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.


	December 31,
In millions	2009		2008 ^(c)		2007 ^(b)(c)		2006 ^(b)(c)		2005 ^(b)(c)
Balance Sheet data:
Current assets	$	5,441	$	5,130	$	4,416	$	4,130	$	3,808
Property, plant and equipment, net		27,341		25,813		24,153		22,775		21,981
Noncurrent regulatory assets		4,872		5,940		5,133		5,808		4,734
Goodwill ^(a)		2,625		2,625		2,625		2,694		3,475
Other deferred debits and other assets		8,901		8,038		8,760		7,933		7,858

Total assets	$	49,180	$	47,546	$	45,087	$	43,340	$	41,856

Current liabilities	$	4,238	$	3,811	$	5,466	$	4,871	$	5,759
Long-term debt, including long-term debt to financing trusts		11,385		12,592		11,965		11,911		11,760
Noncurrent regulatory liabilities		3,492		2,520		3,301		3,025		2,518
Other deferred credits and other liabilities		17,338		17,489		14,131		13,439		12,606
Minority interest		—		—		—		—		1
Preferred securities of subsidiary		87		87		87		87		87
Shareholders’ equity		12,640		11,047		10,137		10,007		9,125

Total liabilities and shareholders’ equity	$	49,180	$	47,546	$	45,087	$	43,340	$	41,856

(a)	The changes between 2006 and 2005 were primarily due to the impact of the goodwill impairment charge of $776 million in 2006.

(b)	Exelon and Generation retrospectively reclassified certain assets and liabilities in accordance with the applicable authoritative guidance for offsetting amounts related to qualifying derivative contracts.

(c)

Exelon and Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform to the current year presentation. Refer to Note 8 of the Combined Notes to Consolidated Financial Statements for further discussion.

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 Operations included in ITEM 7 of this Report on Form 10-K.


	For the Years Ended December 31,
in millions, except for per share data	2009		2008		2007		2006		2005
Statement of Operations data:
Operating revenues	$	9,703	$	10,754	$	10,749	$	9,143	$	9,046
Operating income		3,295		3,994		3,392		2,396		1,852
Income from continuing operations	$	2,122	$	2,258	$	2,025	$	1,403	$	1,109
Income (loss) from discontinued operations		—		20		4		4		19
Income before cumulative effect of changes in accounting principles		2,122		2,278		2,029		1,407		1,128
Cumulative effect of changes in accounting principles (net of income taxes)		—		—		—		—		(30	)

Net income	$	2,122	$	2,278	$	2,029	$	1,407	$	1,098


	December 31,
in millions	2009		2008 ^(a)		2007 ^(a,b)		2006 ^(a,b)		2005 ^(a,b)
Balance Sheet data:
Current assets	$	3,360	$	3,486	$	2,160	$	2,571	$	2,211
Property, plant and equipment, net		9,809		8,907		8,043		7,514		7,464
Deferred debits and other assets		9,237		7,691		8,044		7,845		7,108

Total assets	$	22,406	$	20,084	$	18,247	$	17,930	$	16,783

Current liabilities	$	2,262	$	2,168	$	1,917	$	1,990	$	2,596
Long-term debt		2,967		2,502		2,513		1,778		1,788
Deferred credits and other liabilities		10,385		8,848		9,447		8,678		8,417
Minority interest		2		1		1		1		2
Member’s equity		6,790		6,565		4,369		5,483		3,980

Total liabilities and member’s equity	$	22,406	$	20,084	$	18,247	$	17,930	$	16,783

(a)

Exelon and Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with the current year presentation. Refer to Note 8 of the Combined Notes to Consolidated Financial Statements for further discussion.

(b)	Exelon and Generation reclassified certain assets and liabilities in accordance with the applicable authoritative guidance for offsetting amounts related to qualifying derivative contracts.

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 Operations included in ITEM 7 of this Report on Form 10-K.


	For the Years Ended December 31,
in millions, except for per share data	2009		2008		2007		2006			2005
Statement of Operations data:
Operating revenues	$	5,774	$	6,136	$	6,104	$	6,101		$	6,264
Operating income (loss)		843		667		512		555			(12	)
Income (loss) before cumulative effect of changes in accounting principles	$	374	$	201	$	165	$	(112	)	$	(676	)
Cumulative effect of a change in accounting principle (net of income taxes)		—		—		—		—			(9	)

Net income (loss) ^(a)	$	374	$	201	$	165	$	(112	)	$	(685	)

(a)	The changes between 2007 and 2006 and 2006 and 2005 were primarily due to the impact of the goodwill impairment charges of $776 million and $1.2 billion in 2006 and 2005, respectively.


	December 31,
in millions	2009		2008		2007		2006		2005
Balance Sheet data:
Current assets	$	1,579	$	1,309	$	1,241	$	1,007	$	1,024
Property, plant and equipment, net		12,125		11,655		11,127		10,457		9,906
Goodwill ^(a)		2,625		2,625		2,625		2,694		3,475
Noncurrent regulatory assets		1,096		858		503		532		280
Other deferred debits and other assets		3,272		2,790		3,880		3,084		2,806

Total assets	$	20,697	$	19,237	$	19,376	$	17,774	$	17,491

Current liabilities	$	1,597	$	1,153	$	1,712	$	1,600	$	2,308
Long-term debt, including long-term debt to financing trusts		4,704		4,915		4,384		4,133		3,541
Noncurrent regulatory liabilities		3,145		2,440		3,447		2,824		2,450
Other deferred credits and other liabilities		4,369		3,994		3,305		2,919		2,796
Shareholders’ equity		6,882		6,735		6,528		6,298		6,396

Total liabilities and shareholders’ equity	$	20,697	$	19,237	$	19,376	$	17,774	$	17,491

(a)	The change between 2006 and 2005 was primarily due to the impact of the goodwill impairment charge of $776 million in 2006.

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 Operations included in ITEM 7 of this Report on Form 10-K.


	For the Years Ended December 31,
in millions, except for per share data	2009		2008		2007		2006		2005
Statement of Operations data:
Operating revenues	$	5,311	$	5,567	$	5,613	$	5,168	$	4,910
Operating income		697		699		947		866		1,049
Income before cumulative effect of changes in accounting principles	$	353	$	325	$	507	$	441	$	520
Cumulative effect of a change in accounting principle (net of income taxes)		—		—		—		—		(3	)
Net income		353		325		507		441		517

Net income on common stock	$	349	$	321	$	503	$	437	$	513


	December 31,
in millions	2009		2008		2007		2006		2005
Balance Sheet data:
Current assets	$	1,006	$	819	$	800	$	762	$	795
Property, plant and equipment, net		5,297		5,074		4,842		4,651		4,471
Noncurrent regulatory assets		1,834		2,597		3,273		3,896		4,454
Other deferred debits and other assets		882		679		895		464		366

Total assets	$	9,019	$	9,169	$	9,810	$	9,773	$	10,086

Current liabilities	$	939	$	981	$	1,516	$	978	$	936
Long-term debt, including long-term debt to financing trusts		2,405		2,960		2,866		3,784		4,143
Noncurrent regulatory liabilities		317		49		250		151		68
Other deferred credits and other liabilities		2,706		2,910		3,068		3,051		3,235
Preferred securities		87		87		87		87		87
Shareholders’ equity		2,565		2,182		2,023		1,722		1,617

Total liabilities and shareholders’ equity	$	9,019	$	9,169	$	9,810	$	9,773	$	10,086

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Exelon

General

Exelon, a utility services holding company, operates through the following principal subsidiaries each of which is treated as an operating segment:

•

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 sale of electricity and the provision of transmission and distribution services in northern Illinois, including the City of Chicago.

•

PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services 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 in the Pennsylvania counties surrounding the City of Philadelphia.

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

Through its business services subsidiary BSC, Exelon provides its subsidiaries with a variety of support services at cost. 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 $2,707 million in 2009 as compared to $2,737 million in 2008, and diluted earnings per average common share were $4.09 in 2009 as compared to $4.13 in 2008. All amounts presented below are before the impact of income tax.

Exelon’s 2009 results were significantly affected by lower revenue net of purchased power and fuel expense at Generation of $411 million. This decrease was primarily due to reduced net mark-to-market gains from its hedging activities of $271 million and unfavorable portfolio and market conditions of $206 million. Additionally, Generation experienced higher nuclear fuel costs of $74 million. Partially offsetting these decreases were lower costs associated with the Illinois Settlement of $123 million.

ComEd experienced higher revenue net of purchased power expense of $155 million despite unfavorable weather conditions and reduced load. Distribution pricing increased ComEd’s operating revenues by $214 million primarily due to the ICC’s September 2008 order in the 2007 distribution rate case. This increase was partially offset by the impact of current economic conditions and unfavorable weather, which reduced ComEd’s load resulting in lower revenue net of purchased power expense of $40 million and $45 million, respectively.

PECO had a slight increase of $16 million in its revenue net of purchased power and fuel expense primarily due to increased gas distribution rates effective January 1, 2009 resulting from the settlement of 2008 rate case, which provided $77 million of additional revenues in 2009. PECO’s increased revenues also reflected the impact of lower electric distribution rates in 2008 of $22 million primarily due

to the refund of the 2007 PURTA settlement (which was completely offset in charges recorded in taxes other than income). Similar to ComEd, these increases were partially offset by the impact of current economic conditions and unfavorable weather, which reduced PECO’s load resulting in lower revenue net of purchased power and fuel expense of $69 million and $21 million, respectively.

Exelon’s 2009 results were also affected by higher operating and maintenance expense at Generation. In March 2009, Generation re-evaluated the fair value of the Handley and Mountain Creek stations due to the continued decline in forward energy prices, which resulted in a $223 million impairment charge. In December 2009, Generation announced that it had notified PJM of its intention to permanently retire four fossil-fired generation units in Pennsylvania because they are no longer economic to operate and are not required to meet demand for electricity in the region. In connection with the announced retirements, Generation recorded a charge of $24 million related to exit costs as well as $32 million of accelerated depreciation.

Additionally, Exelon’s pension and other postretirement benefits expense increased by $160 million in 2009 due to lower than expected pension and postretirement plan asset returns in 2008. There was also a scheduled increase in CTC amortization expense at PECO of $90 million in accordance with its 1998 restructuring settlement and increased depreciation of $69 million across the Registrants due to ongoing capital expenditures.

In response to current market and economic conditions, Exelon implemented a cost savings program in 2009. This initiative included job reductions, for which Exelon recorded a $34 million charge related to severance expenses, and a $350 million discretionary contribution to Exelon’s largest pension fund, which is expected to reduce pension expense over the next ten years. PECO generated additional cost savings through enhancements to credit processes and increased collection and termination activities initiated in 2008, which reduced the allowance for uncollectible accounts expense by $97 million. In addition, ComEd’s and PECO’s incremental storm-related costs decreased by $40 million and $9 million, respectively.

Exelon’s interest expense decreased by $140 million primarily due to lower outstanding debt at ComEd and PECO and lower interest rates on Generation’s SNF obligation. Additionally, Exelon was able to capitalize on favorable capital market conditions in its refinancing of $1.2 billion of debt at Exelon and Generation originally scheduled to mature in 2011. Although this debt offering resulted in $120 million in debt extinguishment costs, it decreased Exelon’s average cost of debt while also extending the maturities of the debt.

Exelon’s 2009 results were also significantly affected by NDT realized and unrealized gains of $256 million in 2009 compared to realized and unrealized losses of $308 million in 2008 for the former AmerGen nuclear generating units and portions of the Peach Bottom nuclear generating units (Non-Regulatory Agreement Units) as a result of improved market performance.

Finally, Exelon reassessed anticipated apportionment of its income, resulting in a change in state deferred income tax rates, and ComEd remeasured income tax uncertainties related to its 1999 sale of fossil generating assets. These two actions resulted in an aggregate non cash gain of $83 million.

For further detail regarding 2009 Financial Results, including explanation of non-GAAP measures, see the discussions of Results of Operations by Segment below.

Outlook for 2010 and Beyond.

Economic and Market Conditions

•

Although financial markets have been relatively stable since last summer, manufacturing has remained weak and unemployment rates are still high. As a result, Exelon continues to be challenged by current economic conditions. The demand for electricity has been lower in the ComEd and PECO service territories, meaning relatively fewer retail sales in both areas than in previous years. Lower demand and other factors associated with the global slowdown in economic activity have caused oil, coal and natural gas prices to fall, and have also depressed wholesale electricity prices and therefore led to lower margins for Exelon’s wholesale generation fleet. With respect to natural gas in particular, the price of which is generally the most closely correlated to the price of electricity, the reduction has been significant. A fundamentally oversupplied natural gas market has resulted at times in prices below $3 per million British Thermal Units. Additionally, factors other than the weak global economy have contributed to lower natural gas prices. In particular, recent technological innovation has enabled the extraction of natural gas from North America’s vast shale formations at a cost that the markets can support even in a lower price environment.

Exelon’s existing hedging policies are intended to reduce price volatility and maintain financial discipline. Although Exelon’s hedging policies have helped protect Exelon’s earnings as markets have declined, a period of prolonged depressed electricity prices would adversely impact Exelon’s and Generation’s results of operations in the future. Further discussion of commodity price risk is included in ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

The volatility in the economy could affect the Registrants’ business. The Registrants have continued to assess the impact, if any, of market developments on their respective financial condition, including access to liquidity, counterparty creditworthiness, and the value of investments and other assets. See PART I. ITEM 1A. Risk Factors for information regarding the effects of continued uncertainty in the capital and credit markets or significant bank failures.

New Growth Opportunities

•

Generation pursues growth opportunities that are consistent with its disciplined approach to investing to maximize shareholder value, taking earnings, cash flow and financial risk into account. During 2009, Generation announced a series of planned power uprates across its nuclear fleet that will generate between 1,300 and 1,500 MW of additional generation capacity within eight years. The uprate projects represent a total investment of approximately $3.5 billion, as measured in current costs. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects, representing approximately one quarter of the planned uprates, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Dresden, LaSalle and Quad Cities plants in Illinois. The remainder of uprate MW will come from additional projects across Generation’s nuclear fleet beginning in 2010 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates have an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the project in light of changing market conditions. The amount of expenditures to implement the plan ultimately will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

•

PECO plans to implement Smart Meter and Smart Grid technologies for all customers within their service territory to comply with Act 129. PECO plans to spend approximately $650 million on Smart Meter and Smart Grid investments, which is expected to be recovered with a return on investment from customers through regulated rates. In October 2009, the DOE announced its intent to award PECO $200 million in the ARRA of 2009 matching grant funds under the Smart Grid Investment Grant Program. PECO will deduct any costs paid with DOE funds from amounts recoverable from customers. The new infrastructure will provide the basis for the communications network and information systems to integrate customer energy usage with utility operations, enabling two-way communication. Assuming successful completion of the DOE negotiations and PECO’s receipt of the full grant on reasonable terms, PECO is committed to implementing expanded initial deployment of 600,000 meters within three years and accelerating universal smart meter deployment from 15 years to 10 years. In addition, PECO may have additional costs associated with the replacement of gas meters and the wind-down of its legacy automated meter reading system.

In October 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs from customers. ComEd expects to have the program fully implemented in early summer 2010. The total anticipated cost of the pilot program is approximately $69 million. The AMI pilot program allows ComEd to study the costs and benefits related to automated metering and to develop the cost estimate of potential full system-wide implementation of AMI. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and lower energy bills. See Note 2 of the Combined Notes to the Financial Statements for more information.

•

In the third quarter of 2009, Exelon established Exelon Transmission, which is a new venture that will seek to capitalize on the growing national market for new transmission lines. Exelon Transmission enters a market in which U.S. companies are projected to spend $60-$100 billion on transmission development projects by 2020. New transmission projects have the potential to reduce congestion, improve reliability, and facilitate movement of renewable energy, such as wind and solar, to population centers where it is needed most. Exelon will leverage existing members of management for the initial phases of the project. Exelon Transmission’s portfolio will evolve over time and may include projects with both traditional, regulated profiles as well as more competitive, market-based investments. Exelon expects to provide $10 million in funding to Exelon Transmission in 2010. Additional expenditures will be determined on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

Liquidity and Cost Management

•

Exelon is subject to significant ongoing cost pressures during these challenging economic times. Exelon is committed to operating its businesses responsibly and managing its operating and capital costs in a manner that serves its customers and produces value for its shareholders. Exelon is also committed to an ongoing strategy to make itself more effective, efficient and innovative. In 2009, Exelon launched a company-wide cost management initiative, which combines short-term actions with long-term change. In the short-term, Exelon realized cost savings of approximately $200 million in 2009 over 2008, primarily as a result of the elimination of 500 positions within BSC and ComEd, productivity improvements and stringent controls on supply spending, contracting and overtime costs. Exelon is committed to maintaining a cost control focus and expects to largely offset increasing pension and benefits expense and general inflation in 2010 with additional cost savings, including freezing executive salaries and reducing employee benefits. With regard to long-term changes, Exelon is analyzing cost trends over the past five years to identify future cost savings opportunities and implementing more planning and performance-measurement tools that allow it to better identify areas for sustainable productivity improvements and cost reductions across the Registrants.

•

The Registrants’ credit facilities largely extend through October 2012 for Exelon, Generation and PECO and February 2011 for ComEd. These credit facilities currently provide sufficient liquidity to the Registrants. Additionally, upon maturity of these credit facilities, the Registrants may not be able to renew or replace these existing facilities at current terms or commitment levels from banks. Consequently, the Registrants may face increased costs for liquidity needs and may choose to establish alternative liquidity sources to supply the balance of their needs beginning in 2010 for ComEd and in 2011 for Exelon, Generation and PECO.

Regulatory Matters

•

In July 2009, comprehensive legislation was enacted into law in Illinois which provides public utility companies the ability to bill or refund customers for the difference between the company’s annual uncollectible expense and amounts collected in rates through a rider mechanism. The legislation allows a public utility company to bill customers for under-collections of accounts starting with 2008 and prospectively. ComEd under-collected approximately $26 million during 2008 and approximately $44 million during 2009. On February 2, 2010, the ICC issued an order approving ComEd’s proposed tariffs for collecting the increases or decreases in uncollectible accounts expense, with minor modifications. With the ICC’s approval of the tariff, ComEd will begin collecting past due amounts in April 2010. ComEd will record the $70 million benefit in the first quarter of 2010. ComEd is also required to make a one-time contribution of approximately $10 million to the Supplemental Low-Income Energy Assistance Fund to assist low-income residential customers through the forgiveness of a portion of past-due amounts.

•

During 2009, PECO, in accordance with its PAPUC-approved DSP Program, conducted two competitive procurements and entered into contracts with various counterparties, which included Generation, to procure electric supply for the residential, small commercial and medium commercial procurement classes beginning in 2011 in preparation for the expiration of its electric generation rate caps and its PPA with Generation on December 31, 2010. PECO will procure additional electric supply through seven more procurements of full requirements and forward purchase energy block contracts of varying lengths in accordance with the plan approved by the PAPUC. PECO has also been engaged in regulatory proceedings including Rate Mitigation Plans, Energy Efficiency and Conservation Plan and other regulatory filings to comply with the requirements of Act 129.

Although these proceedings support competitive, market-based procurement during the 29-month term of the approved DSP Program, elected officials in Pennsylvania have suggested rate-increase deferrals and phase-ins, rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate relief programs that could have a significant impact on PECO and Generation.

•

The Pennsylvania Legislature is currently considering HB 80, which, if enacted into law, would increase the minimum required percentage of electric energy to be procured from alternative energy resources in Pennsylvania, expand the solar purchase and sale requirements and would incorporate advanced coal combustion with limited carbon emissions as an acceptable alternative energy resource.

See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for further detail related to these matters.

Environmental Legislation

•

Exelon supports the passage of comprehensive climate change legislation that balances the need to protect consumers, business and the economy with the urgent need to reduce GHG

emissions in the United States. In June 2009, the U.S. House of Representatives passed H.R. 2454. Among its various components, the bill proposes mandatory, economy-wide GHG reduction targets and goals that would be achieved via a Federal emissions cap-and-trade program. If enacted, H.R. 2454 is expected to increase wholesale power prices as generating units reflect the price of carbon emission permits and the cost of emission reduction technology in their bids to supply energy to wholesale markets in order to recover their costs of compliance with carbon regulation. Due to its overall low-carbon generation portfolio, under the provisions of H.R. 2454, Exelon expects that its operating revenues would increase significantly. In September 2009, the U.S. Senate introduced its version of climate change legislation that is similar to H.R. 2454, but does not yet provide specific details regarding allowance allocations. Any bill passed by the U.S. Senate would need to be reconciled with H.R. 2454, approved by both the U.S. House of Representatives and the U.S. Senate, and signed by President Obama before becoming law.

•

Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. This goal was achieved by December 31, 2008 through Exelon’s planned GHG management efforts, including the previous closure of older, inefficient fossil power plants, reduced leakage of SF₆, increased use of renewable energy and its current energy efficiency initiatives. In 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental strategic plan. The plan, Exelon 2020, details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels). See Item 1. General Business for further discussion of Exelon’s voluntary GHG emissions reductions.

See Note 18 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

Healthcare Reform Legislation

•

In 2009, the U.S. House of Representatives and the U.S. Senate each passed its own version of healthcare reform bills that would fundamentally change the nation’s healthcare system. Due to the uncertainty as to the final outcome of Federal healthcare reform legislation, the Registrants are unable to estimate the effects on their respective results of operations, cash flows or financial positions.

Competitive Markets

•

Generation is exposed to commodity price risk associated with the unhedged portion of its electricity 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 2010 and 2011. 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 currently hedges commodity risk on a ratable basis over the three years leading to the spot market. As of December 31, 2009, the percentage of expected generation hedged was 91%—94%, 69%—72% and 37%—40% for 2010, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load. Generation has been and will continue to be proactive in using hedging strategies to mitigate this price risk in subsequent years as well. PECO has transferred substantially all of its commodity price risk

related to its procurement of electricity to Generation through a PPA that expires on December 31, 2010. Since PECO entered into its PPA with Generation, market prices for energy have generally been higher than the generation rates PECO has paid for purchased power, which represents the rates paid by PECO customers. Generation’s margins on its other sales have therefore generally been higher. The expiration of the PPA with PECO at the end of 2010 will likely result in increases in margins earned by Generation beginning in 2011 for the portion of Generation’s electricity portfolio previously sold to PECO under the PPA. While Generation’s three year ratable hedging program considers the expiration of the PPA the ultimate impact of entering into new power supply contracts will depend on a number of factors, including future wholesale market prices, capacity markets, energy demand and the effects of any new applicable Pennsylvania laws and or rules and regulations promulgated by the PAPUC. Both PECO and ComEd mitigate exposure to commodity price risk through the recovery of procurement costs from retail customers.

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Generation procures coal through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 56% of Generation’s uranium concentrate requirements from 2010 through 2014 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position. Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate price risk associated with certain commodity price exposures.

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 Committees of the Exelon, ComEd and PECO Boards 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. Additional discussion of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)

Generation must make significant estimates and assumptions in accounting for its obligation to decommission its nuclear generating plants in accordance with the authoritative guidance for AROs.

The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses a probability-weighted, discounted cash flow model that considers multiple outcome scenarios based upon significant estimates and assumptions embedded in the following:

Decommissioning Cost Studies. Generation uses decommissioning cost studies on a unit-by-unit basis to provide a marketplace assessment of the costs and timing of decommissioning

activities, which are validated by comparison to current decommissioning projects within its industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years.

Cost Escalation Studies. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the decommissioning period for each of the units. Cost escalation studies are used to determine escalation factors and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. Cost escalation studies are updated on an annual basis.

Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various cost, decommissioning alternatives and timing scenarios on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of actual costs plus 20% (high-cost scenario) or minus 15% (low-cost scenario) 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 LLRW landfill or decontaminated to a level that permits property to be released for unrestricted use shortly after the cessation of operations), Delayed DECON (similar to the DECON scenario but with a delay to allow for spent fuel to be removed from the site prior to onset of decommissioning activities) 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 generally within 60 years after cessation of operations) 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 SNF for disposal, which Generation currently assumes will begin in 2020, based on the DOE’s most recent indication. For more information regarding the estimated date that DOE will begin accepting SNF, see Note 12 of the Combined Notes to Consolidated Financial Statements.

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. The following table illustrates the effects of changing certain ARO assumptions, discussed above, while holding all other assumptions constant (dollars in millions):


Change in ARO Assumption	Increase to ARO at December 31, 2009
Cost escalation studies
Uniform increase in escalation rates of 25 basis points	$	364
Probabilistic cash flow models
Increase the likelihood of the high-cost scenario by 10 percentage points and decrease the likelihood of the low-cost scenario by 10 percentage points	$	126
Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of the SAFSTOR scenario by 10 percentage points	$	231
Increase the likelihood of operating through current license lives by 10 percentage points and decrease the likelihood of operating through anticipated license renewals by 10 percentage points	$	305

If the estimated date for DOE acceptance of SNF were to be extended to 2030, Generation’s aggregate nuclear decommissioning obligation would be reduced by an immaterial amount.

Under the authoritative guidance, the nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions or the expected timing or estimated amount of the future undiscounted cash flows required to decommission the nuclear plants. For more information regarding accounting for nuclear decommissioning obligations, see Notes 1 and 11 of the Combined Notes to Consolidated Financial Statements.

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation)

The NDT fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation’s investment policies place limitations on the types and investment grade ratings of the securities that may be held by the NDTs. These policies restrict the NDT funds from holding alternative investments and limit the NDT funds’ exposures to investments in highly illiquid markets. On January 1, 2008, in order to align the accounting treatment of changes in the fair value of NDT fund investments in both an unrealized gain and an unrealized loss position, Generation elected the irrevocable option to measure financial assets and liabilities at fair value with changes in fair value recognized in earnings with respect to these investments. Therefore, the investments are carried at fair value with all changes in fair value being recognized through the statement of operations. See Notes 7 and 11 of the Combined Notes to Consolidated Financial Statements for further discussion on the NDT funds.

Asset Impairments (Exelon, Generation, ComEd and PECO)

Goodwill (Exelon and ComEd)

Exelon and ComEd have goodwill relating to the acquisition of ComEd in 2000 under the PECO/Unicom Merger. Under the provisions of the authoritative guidance for goodwill, Exelon and ComEd perform assessments for impairment of their goodwill at least annually or more frequently if an event occurs, such as a significant negative regulatory outcome, or circumstances change that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. The impairment assessment is performed using a two-step, fair value based test. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. In general, in applying the second step, fair value increases to assets and/or fair value decreases to liabilities would increase the size of any impairment. For example, a decrease in the fair value of ComEd’s debt would increase the size of any impairment and vice versa. Application of the goodwill impairment test requires management judgment, including the identification of reporting units, assigning assets, liabilities and goodwill to reporting units, determining the fair value of the reporting unit and, in applying the second step (if needed), determining the fair value of specific assets and liabilities of the reporting entity. See Note 6 of the Combined Notes to Consolidated Financial Statements for additional information.

The FASB’s fair value measurement and disclosure guidance for all nonrecurring fair value measurements of nonfinancial assets and liabilities, including goodwill, was effective for the Registrants as of January 1, 2009. This authoritative guidance clarified that fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. As a result, Exelon and ComEd now estimate the fair value of the ComEd reporting unit using a weighted combination of a discounted cash flow analysis and a market multiples analysis instead of the expected cash flow approach used in 2008 and prior years. The discounted cash flow analysis relies on a single scenario reflecting “base case” or

“best estimate” projected cash flows for ComEd’s business and includes an estimate of ComEd’s terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include ComEd’s capital structure, discount and growth rates, utility sector market performance, operating and capital expenditure requirements, fair value of debt, the selection of comparable companies and recent transactions. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reporting units to Exelon’s enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multiples analysis.

The regulatory environment has provided more certainty related to ComEd’s future cash flows. Although financial markets have stabilized over the past year, current economic conditions continue to impact the market-related assumptions used in the November 1, 2009 annual assessment. While ComEd did not recognize an impairment in 2009, deterioration of the market-related factors used in the impairment review could potentially result in a future impairment loss of ComEd’s goodwill, which could be material. If any combination of changes to significant assumptions resulted in a 5% reduction in fair value as of November 1, 2009, ComEd still would have passed the first step of the goodwill assessment.

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. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets include general deterioration in the business climate, including current economic energy market conditions, deterioration in the physical condition or operating performance of the asset, specific regulatory disallowance or plans to dispose of a long-lived asset significantly before the end of its useful life. 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 evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets are largely independent of other groups of assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units. For ComEd and PECO, the lowest level of independent cash flows is determined by evaluation of several factors including the ratemaking jurisdiction in which they operate and the type of service or commodity. For ComEd the lowest level of independent cash flows is transmission and distribution and for PECO, the lowest level of independent cash flows is transmission, distribution and gas. Impairment may occur when the carrying value of the asset or asset group exceeds the associated future undiscounted cash flows. When the undiscounted cash flow analysis indicates that the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. An impairment is reported by the affected Registrant as a reduction to both the long-lived asset and current period earnings. See Note 4 of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment evaluations made by Generation.

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

The Registrants have significant investments 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. Depreciation rates incorporate assumptions on interim retirements based on actual historical retirement experience. To the extent interim retirement patterns change, this could have a significant impact on the amount of depreciation expense recorded in the income statement. Changes to depreciation estimates resulting from a change in the estimated end of service lives could have a significant impact on the amount of depreciation expense recorded in the income statement.

The estimated service lives of the nuclear generating facilities are based on the estimated useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses for all of Generation’s operating nuclear generating stations. While Generation has received license renewals for certain facilities, and has applied for or expects to apply for and obtain approval of license renewals for the remaining facilities, circumstances may arise that would prevent Generation from obtaining additional license renewals. 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. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. 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.

ComEd is required to file a depreciation rate study at least every five years with the ICC. ComEd filed a depreciation rate study with the ICC in January 2009, which resulted in the implementation of new depreciation rates effective January 1, 2009.

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.

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

Exelon sponsors defined benefit pension plans and postretirement benefit plans for substantially all Generation, ComEd, PECO, and Exelon Corporate employees. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and postretirement benefit plans.

The measurement of the plan obligations and costs associated with providing benefits under these plans involve several factors, including development of valuation assumptions and determining accounting elections. When developing the various assumptions that are required, Exelon considers historical information as well as future expectations. The measurement of benefit costs is affected by the actual rate of return on plan assets, and assumptions, including the long-term expected rate of return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, the long-term expected investment rate credited to employees of certain plans, the anticipated rate of increase of healthcare costs and the level of benefits provided to employees and retirees, among other factors. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. As required by the authoritative guidance, the impact of assumption changes on pension and other postretirement benefit

obligations is generally recognized over the expected average remaining service period of the employees rather than immediately recognized in the income statement. Pension and postretirement benefit costs attributed to the operating companies are labor costs and ultimately allocated to projects within the operating companies, some of which are capitalized.

Pension and postretirement benefit plan assets include equity and fixed income securities held through funds as well as certain alternative investment classes. See Note 13 of the Combined Notes to Consolidated Financial Statements for information on fair value measurements of pension and other postretirement plan assets, including valuation techniques and classification in accordance with authoritative guidance under the fair value hierarchy.

Expected Rate of Return on Plan Assets. The long-term expected rate of return on plan assets assumption used in calculating pension costs was 8.50%, 8.75% and 8.75% for 2009, 2008 and 2007, respectively. The weighted average EROA assumption used in calculating other postretirement benefit costs was 8.10%, 7.80% and 7.85% in 2009, 2008 and 2007 respectively. The pension trust activity is non-taxable, while other postretirement benefit trust activity is partially taxable. The EROA is based on current asset allocations as described in Note 13 of the Combined Notes to Consolidated Financial Statements. A change in the asset allocation strategy could impact the EROA and related costs. Exelon will use an EROA of 8.50% and 7.83%, for estimating its 2010 pension costs and other postretirement benefit costs, respectively.

Exelon calculates the expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefit plan assets, Exelon uses fair value to calculate the MRV.

Actual asset returns have a significant effect on the costs reported for the Exelon-sponsored pension and other postretirement benefit plans. The actual asset returns across the Registrant’s pension and other postretirement benefit plans for the year ended December 31, 2009 were approximately 21% compared to an expected long-term return assumption of 8.5% and 8.1%, respectively. Those return levels are expected to decrease 2010 and 2011 benefit costs as follows:


(dollars in millions)	Decrease in 2010 Pension Cost			Decrease in 2010 Postretirement Benefit Cost			Decrease in 2011 Pension Cost			Decrease in 2011 Postretirement Benefit Cost
2009 asset returns of 21%	$	(28	)	$	(29	)	$	(27	)	$	(28	)

This information assumes that movements in asset returns occur absent changes to other actuarial assumptions, and does not consider any actions management may take, such as changes to the amount and timing of future contributions. The actuarial assumptions used in the determination of pension and postretirement benefit costs are interrelated and changes in other assumptions could have the impact of offsetting all or a portion of the potential decrease in benefit costs set forth above. For example, decreases in actual discount rates, absent changes in other assumptions, increase pension and postretirement costs and obligations. Sensitivities of cost and obligations to key actuarial assumptions are discussed in further detail below.

Discount Rate. The discount rate for determining both the pension and other postretirement benefit obligations was 5.83%, 6.09% and 6.20% at December 31, 2009, 2008 and 2007, respectively. At December 31, 2009, 2008 and 2007, the discount rate was determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality 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 utilizes an analytical tool developed by its actuaries to select the discount rates.

The discount rate assumptions used to determine the obligation at year end will be used to determine the cost for the following year. Exelon will use a discount rate of 5.83% for estimating its 2010 pension costs and other postretirement benefit costs.

Healthcare Cost Trend Rate. Assumed healthcare cost trend rates also have a significant effect on the costs reported for Exelon’s other postretirement benefit plans. In determining the healthcare cost trend rate, Exelon reviews actual recent cost trends and projected future trends.

Sensitivity to Changes in Key Assumptions: The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant (dollars in millions):


Actuarial Assumption	Change in Assumption	Pension		Other Postretirement Benefits			Total
Change in 2009 cost:
Discount rate	(0.5)%	$	44	$	26		$	70
EROA	(0.5)%		46		6			52
Healthcare trend rate	1.00%		—		49			49
	(1.00)%		—		(40	)		(40	)
	Extend the year at which the ultimate healthcare trend rate of 5% is forecasted to be reached by 5 years		—		19			19
Change in benefit obligation at December 31, 2009:
Discount rate	(0.5)%		727		222			949
EROA	(0.5)%		—		—			—
Healthcare trend rate	1.00%		—		448			448
	(1.00)%		—		(372	)		(372	)
	Extend the year at which the ultimate healthcare trend rate of 5% is forecasted to be reached by 5 years		—		152			152

Average Remaining Service Period. For pension benefits, Exelon amortizes its unrecognized prior service costs and certain of its actuarial gains and losses, as applicable, based on participants’ average remaining service periods. For other postretirement benefits, Exelon amortizes its unrecognized prior service costs over participants’ average remaining service period related to eligibility age and amortizes its transition obligations and certain actuarial gains and losses over

participants’ average remaining service period to expected retirement. The average remaining service period of defined benefit pension plan participants was 12.7 years, 12.8 years and 13.0 years for the years ended December 31, 2009, 2008 and 2007, respectively. The average remaining service period of postretirement benefit plan participants related to eligibility age was 6.8 years, 6.9 years and 6.9 years for the years ended December 31, 2009, 2008 and 2007, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 9.2 years, 9.4 years and 9.7 years for the years ended December 31, 2009, 2008 and 2007, respectively.

Regulatory Accounting (Exelon, ComEd and PECO)

Exelon, ComEd and PECO account for their regulated electric and gas operations in accordance with the authoritative guidance for accounting for certain types of regulations, 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 future recovery through rates charged to customers. Regulatory liabilities represent revenues collected from customers in excess of prescribed recovery that must be refunded to customers through an adjustment of billing rates. Use of this guidance is applicable to utility operations that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable expectation that all costs will be recoverable from customers through rates. As of December 31, 2009, 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 those operations no longer meets the criteria of this guidance, Exelon, ComEd and PECO are required to eliminate the financial statement effects of regulation for that part of those operations, 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. The impact of not meeting the criteria would be material to the financial statements of Exelon, ComEd and PECO. At December 31, 2009, the extraordinary gain could have been as much as $1.7 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2009, the extraordinary charge could have been as much as $1.5 billion (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. Exelon would record an extraordinary gain or charge in an equal amount related to ComEd’s and PECO’s regulatory assets and liabilities in addition to a charge against OCI (before taxes) of up to $2.5 billion and $92 million for ComEd and PECO, respectively, 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 could be significant and at least partially offset the extraordinary gain discussed above. A significant decrease in equity as a result of any changes could limit the ability of ComEd and PECO to pay dividends under Federal and state law and cause significant volatility in future results of operations. See Notes 2, 6 and 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory issues, ComEd’s goodwill and the significant regulatory assets and liabilities of Exelon, ComEd and PECO, respectively.

For each regulatory jurisdiction in which 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 and recent rate orders, including for other regulated entities in the same jurisdiction. Furthermore, Exelon, ComEd and PECO make other judgments related to the financial statement impact of their regulatory environments, such as the types of adjustments to rate base that will be acceptable to regulatory bodies and the types of costs and the extent, if any, to which those costs will be recoverable through rates. Additionally, estimates are made in accordance with the authoritative guidance for contingencies, as to the amount of revenues billed under certain regulatory orders that will ultimately be refunded to customers upon finalization of the appropriate regulatory process. These assessments are based, to the extent possible, on past relevant

experience with regulatory bodies, known circumstances specific to a particular matter, discussions held with the applicable regulatory body and other factors. If the assessments and estimates made by Exelon, ComEd and PECO are ultimately different than actual events, the impact on their results of operations, financial position, and cash flows could be material.

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

The Registrants utilize derivative instruments 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 uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases and other energy-related products marketed and purchased. Additionally, Generation enters into energy-related derivatives for proprietary trading purposes. ComEd has entered into contracts to procure energy, capacity and ancillary services. In addition, ComEd has a financial swap contract with Generation that extends into 2013. PECO has entered into derivative natural gas contracts to hedge its long-term price risk in the natural gas market. As part of the preparation for the expiration of the PPA with Generation at the end of 2010, PECO has entered into derivative contracts to procure electric supply through a competitive RFP process as outlined in its PAPUC-approved DSP Program. ComEd and PECO do not enter into derivatives for proprietary trading purposes. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether or not a contract qualifies as a derivative under this guidance requires that management exercise significant judgment, including assessing the market liquidity as well as determining whether a contract has one or more underlyings and one or more notional amounts. Further, interpretive guidance related to the authoritative literature continues to evolve, including how it applies to energy and energy-related products. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance related to derivatives, could result in previously excluded contracts being subject to the provisions of the authoritative derivative guidance. Generation has determined that contracts to purchase uranium do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Generation begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Generation’s other derivative instruments. In this case, if market prices differ from the underlying prices of the contracts, Generation would be required to record a mark-to-market gain or loss, which may have a material impact to Exelon’s and Generation’s financial positions and results of operations.

Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting and for energy-related derivatives entered for proprietary trading purposes, changes in the fair value of the derivatives are recognized in earnings each period except for ComEd and PECO, in which changes in the fair value each period are recorded in a regulatory asset or liability.

Normal Purchases and Normal Sales Exception. Determining whether a contract qualifies for the normal purchases and normal sales exception requires that management exercise judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as normal purchases and normal sales are recognized when the underlying physical transaction is completed. Contracts which qualify for the normal purchases and normal sales exception are those for which 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 the authoritative guidance, the transactions have been designated as normal purchases and normal sales and are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. The contracts that ComEd has entered into with Generation and other suppliers as part of the initial ComEd procurement auction and the subsequent RFP process, PECO’s full requirements fixed price contracts under the PAPUC-approved DSP program and all of PECO’s natural gas supply agreements that are derivatives, qualify for the normal purchases and normal sales exception. 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 at Generation or offset by a regulatory asset or liability at ComEd and PECO. Thereafter, future changes in fair value would be recorded in the balance sheet and recognized through earnings at Generation. Triggering events that could result in a contract’s loss of the normal purchase and normal sale designation, because it is no longer probable that the contract will result in physical delivery, include changes in business requirements, changes in counterparty credit and book-outs (financial settlements).

Commodity Contracts. Identification of a commodity 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 commodity contract and the expected future purchase or sale of the commodity 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 a commodity 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 the authoritative guidance, hedge accounting is discontinued and changes in the fair value of the derivative are recorded through earnings at Generation or offset by a regulatory asset or liability at ComEd and PECO.

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. In accordance with the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based derivatives are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges are categorized in Level 2. These price quotations

reflect the average of the bid-ask mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The Registrant’s non-exchange-based derivatives are predominately at liquid trading points. The remainder of non-exchange-based derivative contracts is valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For non-exchange-based derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, model inputs generally would include both observable and unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in its assessment of nonperformance risk, including credit risk. The impacts of credit and nonperformance risk were not material to the financial statements.

Interest Rate Derivative Instruments. The Registrants may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. 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. The Registrants use a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, as well as market parameters such as interest rates and volatility. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy.

See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 7 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

Taxation (Exelon, Generation, ComEd and PECO)

Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using 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 in accordance with the authoritative guidance for accounting for uncertain tax positions. 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. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of unrecognized tax benefits to be recorded in the Registrants’ consolidated financial statements.

The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. The Registrants also assess 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 record valuation allowances for deferred tax assets when the Registrants conclude it is more likely than not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, the Registrants’ forecasted financial condition and results of operations in future periods, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. While the Registrants believe the resulting tax balances as of December 31, 2009 and 2008 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding taxes.

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 estimable 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 their consolidated financial statements.

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. These matters, 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.

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. 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.

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

The allowance for uncollectible accounts reflects the Registrants’ best estimates of probable losses on 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 consistent with approved regulatory guidelines. ComEd and PECO are each currently obligated to provide service to all electric customers within their respective franchised territories and are prohibited from terminating electric service to certain residential customers due to nonpayment during certain months of the year. ComEd’s and PECO’s provisions for uncollectible accounts will continue to be affected by changes in prices and economic conditions as well as changes in ICC and PAPUC regulations, respectively.

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. 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.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the years ended December 31, 2009, 2008 and 2007 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Net Income (Loss) from Continuing Operations by Business Segment


	2009			2008			Favorable (unfavorable) 2009 vs. 2008 variance			2007		Favorable (unfavorable) 2008 vs. 2007 variance
Generation	$	2,122		$	2,258		$	(136	)	$	2,025	$	233
ComEd		374			201			173			165		36
PECO		353			325			28			507		(182	)
Other ^(a)		(143	)		(67	)		(76	)		29		(96	)

Total	$	2,706		$	2,717		$	(11	)	$	2,726	$	(9	)

(a)	Other primarily includes corporate operations, BSC, investments in synthetic fuel-producing facilities and intersegment eliminations.

Net Income (Loss) by Business Segment


	2009			2008			Favorable (unfavorable) 2009 vs. 2008 variance			2007		Favorable (unfavorable) 2008 vs. 2007 variance
Generation	$	2,122		$	2,278		$	(156	)	$	2,029	$	249
ComEd		374			201			173			165		36
PECO		353			325			28			507		(182	)
Other ^(a)		(142	)		(67	)		(75	)		35		(102	)

Total	$	2,707		$	2,737		$	(30	)	$	2,736	$	1

(a)	Other primarily includes corporate operations, BSC, investments in synthetic fuel-producing facilities and intersegment eliminations.

Results of Operations—Generation


	2009			2008			Favorable (unfavorable) 2009 vs. 2008 variance			2007			Favorable (unfavorable) 2008 vs. 2007 variance
Operating revenues	$	9,703		$	10,754		$	(1,051	)	$	10,749		$	5
Purchased power and fuel expense		2,932			3,572			640			4,451			879

Revenue net of purchased power and fuel expense^(a)		6,771			7,182			(411	)		6,298			884
Other operating expenses
Operating and maintenance		2,938			2,717			(221	)		2,454			(263	)
Depreciation and amortization		333			274			(59	)		267			(7	)
Taxes other than income		205			197			(8	)		185			(12	)

Total other operating expenses		3,476			3,188			(288	)		2,906			(282	)

Operating income		3,295			3,994			(699	)		3,392			602

Other income and deductions
Interest expense		(113	)		(136	)		23			(161	)		25
Equity in earnings (losses) of investments		(3	)		(1	)		(2	)		1			(2	)
Other, net		376			(469	)		845			155			(624	)

Total other income and deductions		260			(606	)		866			(5	)		(601	)

Income from continuing operations before income taxes		3,555			3,388			167			3,387			1
Income taxes		1,433			1,130			(303	)		1,362			232

Income from continuing operations		2,122			2,258			(136	)		2,025			233
Income from discontinued operations, net of income taxes		—			20			(20	)		4			16

Net income	$	2,122		$	2,278		$	(156	)	$	2,029		$	249

(a)

Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

Net Income

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Generation’s 2009 results compared to 2008 were significantly affected by lower revenue net of purchased power and fuel expense primarily due to unfavorable portfolio and market conditions, including decreased net mark-to-market gains from its hedging activities, and revenue from certain long options in Generation’s proprietary trading portfolio recorded in 2008. Additionally, Generation’s revenue net of purchased power and fuel expense was affected by gains related to the settlement of uranium supply agreements in 2008 and higher nuclear fuel costs in 2009 due to rising nuclear fuel prices. The decrease in Generation’s revenues net of purchased power and fuel expense was partially offset by lower costs related to the Illinois Settlement.

Generation’s 2009 results compared to 2008 were further affected by higher operating and maintenance expenses. Higher operating and maintenance expenses were primarily due to a $223 million charge associated with the impairment of the Handley and Mountain Creek stations and costs associated with the announced shut-down of three coal-fired and one dual fossil-fired generation unit in Pennsylvania. These actions were a direct result of current and future expected market conditions. Market conditions also contributed to lower than expected pension and postretirement plan asset returns in 2008, which resulted in higher pension and other postretirement benefits expense in 2009. Higher operating and maintenance expenses were partially offset by the favorable results of Exelon’s companywide cost savings initiative and lower nuclear refueling outage costs.

Additionally, due to a significant rebound in the financial markets, Generation experienced strong performance in its NDT funds in 2009. As a result, Generation’s earnings improved as its NDTs of the Non-Regulatory Agreement Units had significant net realized and unrealized gains in 2009 compared to significant net realized and unrealized losses in 2008.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. Generation’s 2008 results were significantly affected by higher revenue net of purchased power and fuel expense compared to 2007 primarily due to favorable portfolio and market conditions, including increased net mark-to-market gains from its hedging activities, and revenue from certain long options in Generation’s proprietary trading portfolio recorded in 2008, which were primarily the result of favorable energy prices. Additionally, Generation’s revenue net of purchased power and fuel expense was affected by lower costs incurred in conjunction with the Illinois Settlement and the gain on the termination of the State Line Energy, L.L.C. (State Line) PPA in 2007.

Generation’s 2008 results compared to 2007 were further affected by higher operating and maintenance expenses. Higher operating and maintenance expenses included higher nuclear planned refueling outage costs and higher labor and contracting costs.

Additionally, due to a sharp decline in the financial markets, Generation’s NDTs of its Non-Regulatory Agreement Units had significant net realized and unrealized losses in 2008.

Operating Revenues

For the years ended December 31, 2009, 2008 and 2007, Generation’s sales were as follows:


Revenue	2009			2008			2009 vs. 2008					2007			2008 vs. 2007
Revenue	2009			2008			Variance			% Change		2007			Variance			% Change
Electric sales to affiliates	$	3,470		$	3,588		$	(118	)	(3.3	)%	$	3,537		$	51		1.4	%
Wholesale and retail electric sales		5,978			6,693			(715	)	(10.7	)%		6,834			(141	)	(2.1	)%

Total electric sales revenue		9,448			10,281			(833	)	(8.1	)%		10,371			(90	)	(0.9	)%
Retail gas sales		295			497			(202	)	(40.6	)%		449			48		10.7	%
Trading portfolio		1			106			(105	)	(99.1	)%		43			63		146.5	%
Other operating revenue^(a)		(41	)		(130	)		89		68.5	%		(114	)		(16	)	(14.0	)%

Total operating revenues	$	9,703		$	10,754		$	(1,051	)	(9.8	)%	$	10,749		$	5		0.0	%

(a)	Includes costs incurred for the Illinois Settlement and revenues relating to fossil fuel sales and decommissioning revenue from PECO during 2009, 2008 and 2007.


Sales (in GWh)	2009	2008	2009 vs. 2008				2007	2008 vs. 2007
Sales (in GWh)	2009	2008	Variance		% Change		2007	Variance		% Change
Electric sales to affiliates	58,643	64,652	(6,009	)	(9.3	)%	64,406	246		0.4	%
Wholesale and retail electric sales	114,422	111,522	2,900		2.6	%	125,244	(13,722	)	(11.0	)%

Total electric sales	173,065	176,174	(3,109	)	(1.8	)%	189,650	(13,476	)	(7.1	)%

Trading volumes of 7,578 GWh, 8,891 GWh and 20,323 GWh for 2009, 2008 and 2007, respectively, are not included in the table above.

Electric sales to affiliates. The changes in Generation’s electric sales to affiliates for 2009 compared to 2008 and 2008 compared to 2007 consisted of the following:


Electric sales to affiliates	Variance 2009 vs. 2008									Variance 2008 vs. 2007
	Price			Volume			(Decrease)			Price			Volume			Increase
ComEd	$	264		$	(313	)	$	(49	)	$	(13	)	$	40		$	27
PECO		(14	)		(55	)		(69	)		43			(19	)		24

Total	$	250		$	(368	)	$	(118	)	$	30		$	21		$	51

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Of the $264 million price variance in the ComEd territories, $294 million is related to an increase in settlements from the ComEd swap. This increase is partially offset by decreased prices realized for sales under the RFP. The volume decrease in the ComEd territories is due primarily to the expiration of certain tranches served under the auction contract, partially offset by an increase in deliveries to ComEd under the RFP. In the PECO territories, the decrease in price reflects an unfavorable change in the mix of average pricing related to PECO’s PPA with Generation and the volume decrease was primarily due to unfavorable economic conditions.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. In the ComEd territories, the volume increase was primarily the result of an acquisition by Generation of an unrelated third party’s supply obligations under the ComEd auction effective January 1, 2008, as well as volumes sold under the ComEd RFP, which started in September 2008. The price decrease in the ComEd

territories was largely due to final reconciliation activity recorded in 2007 associated with the full requirements ComEd PPA which ended on December 31, 2006. This decrease was offset by a $29 million increase in revenue related to the ComEd RFP. In the PECO territories, the price increase reflects a favorable change in the mix of average pricing related to PECO’s PPA with Generation, in addition to the effects of the last scheduled rate increase under the PPA, which took effect in mid-January 2007. The volume decrease in the PECO territories was primarily due to unfavorable weather conditions.

Wholesale and retail electric sales. The decrease in Generation’s wholesale and retail electric sales for 2009 compared to 2008 and 2008 compared to 2007 consisted of the following:


	Increase (Decrease)
	2009 vs. 2008			2008 vs. 2007
Price	$	(891	)	$	606
Volume		176			(747	)

Decrease in wholesale and retail electric sales	$	(715	)	$	(141	)

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. The decrease was primarily the result of an overall decrease in market prices, partially mitigated by higher volumes of generation sold to the wholesale and retail markets as a result of a decrease in affiliate load served and increased nuclear generation as a result of a decrease in refueling and non-refueling outage days.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. The decrease in volumes was reflective of an increased use of financial instruments versus physical contracts in addition to lower volumes of generation sold to the market, including the termination of Generation’s PPA with State Line in October 2007. The increase in price was primarily the result of an overall increase in market prices.

Retail gas sales. Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Retail gas sales decreased $202 million of which $131 million was due to lower realized prices and $71 million was due to lower volumes as a result of decreased demand.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. Retail gas sales increased $48 million of which $74 million was due to higher realized prices, partially offset by a $26 million decrease due to lower volumes as a result of decreased demand.

Trading Portfolio. Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. The trading portfolio revenues decreased $105 million which was due primarily to earnings in 2008 from certain long options in the proprietary trading portfolio.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. The trading portfolio revenues increased $63 million which was due primarily to earnings from certain long options in the proprietary trading portfolio in 2008.

Other revenue. Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. The increase in other revenues was primarily due to $123 million in reduced customer credits issued to ComEd and Ameren associated with the 2007 Illinois Settlement further described in Note 2 of the Combined Notes to Consolidated Financial Statements, partially offset by $24 million in lower fuel sales.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. The decrease in other revenues was primarily due to $223 million of income in 2007 associated with the termination of State Line PPA, partially offset by $187 million in reduced customer credits issued to ComEd and Ameren associated with the 2007 Illinois Settlement and a $14 million Salem oil spill settlement received in December 2008. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding the oil spill settlement.

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


			2009 vs. 2008					2008 vs. 2007
Supply Source (in GWh)	2009	2008	Variance		% Change		2007	Variance		% Change
Nuclear generation ^(a)	139,670	139,342	328		0.2	%	140,359	(1,017	)	(0.7	)%
Purchases	23,206	26,263	(3,057	)	(11.6	)%	38,021	(11,758	)	(30.9	)%
Fossil and hydroelectric generation	10,189	10,569	(380	)	(3.6	)%	11,270	(701	)	(6.2	)%

Total supply	173,065	176,174	(3,109	)	(1.8	)%	189,650	(13,476	)	(7.1	)%

(a)	Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem Generating Station (Salem), which is operated by PSEG Nuclear, LLC.

The following table presents changes in Generation’s purchased power and fuel expense for 2009 compared to 2008 and 2008 compared to 2007. Generation considers the aggregation of purchased power and fuel expense as a useful measure to analyze the profitability of electric operations between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, the aggregation of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information Generation provides elsewhere in this report.


	Variance 2009 vs. 2008									Variance 2008 vs. 2007
	Price			Volume			Total Increase (Decrease)			Price			Volume			Total Increase (Decrease)
Purchased power costs and tolling agreement costs^(a)	$	(610	)	$	(306	)	$	(916	)	$	767		$	(825	)	$	(58	)
Generation costs^(b)		168			—			168			(77	)		(12	)		(89	)
Retail Fuel Costs		(146	)		(70	)		(216	)		87			(25	)		62
Mark-to-market		n.m.			n.m.			271			n.m.			n.m.			(623	)

Decrease in purchased power and fuel expense							$	(693	)							$	(708	)

(a)

Variance for 2008 as compared to 2007 presented excludes the net impact of a $119 million loss recorded in 2007 associated with Generation’s tolling agreement with Georgia Power related to the contract with Tenaska. See Note 18 of the Combined Notes to the Consolidated Financial Statements for additional information.

(b)	Variance for both periods excludes gains of approximately $53 million related to non-performance claims for uranium supply agreements recorded in 2008.

n.m.	Not meaningful.

Purchased Power Costs and Tolling Agreement Costs.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Purchased power costs include all costs associated with the procurement of electricity including capacity, energy and fuel costs associated with tolling agreements. Generation incurred overall lower prices for purchased power as a result of the decline in market prices. Generation’s decreased purchased power volumes were driven by unfavorable market conditions.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. Generation had lower purchased power volumes primarily due to market conditions that resulted in decreased purchases from contracted units as well as decreased volumes due to the termination of the State Line PPA in October 2007. The decrease in volumes was also reflective of an increased use of financial instruments versus physical contracts. Generation incurred overall higher prices for purchased power as a result of an overall increase in market prices. Further, Generation’s purchased power costs increased $28 million due to the favorable PJM billing dispute settlement with PPL in the first quarter of 2007.

Generation Costs. Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Generation costs include fuel costs for internally-generated energy. Generation experienced overall higher generation costs for the year ended December 31, 2009, as compared to the same period in 2008 primarily as a result of an increase in the cost of nuclear and fossil fuels.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. Generation experienced overall lower generation costs for the year ended December 31, 2008, as compared to the same period in 2007 due to decreased fossil fuel costs, lower volumes and gains associated with uranium supply agreement costs, partially offset by increased costs for uranium and fossil fuel inventory impairments of $21 million during the year ended December 31, 2008.

Retail Fuel Costs. Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Retail fuel cost includes retail gas purchases. The changes in Generation’s retail fuel costs for 2009 as compared to 2008 consisted of overall lower prices resulting in a decrease of $146 million. This was in addition to lower demand resulting in a volume decrease of $70 million.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. The changes in Generation’s retail fuel costs for 2008 as compared to 2007 consisted of overall higher prices resulting in an increase of $75 million, in addition to a retail gas inventory impairment of $12 million during the year 2008. These increases were offset by lower volumes caused by lower demand, which resulted in a decrease of $25 million.

Mark-to-market. Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market gains on power hedging activities were $94 million in 2009, including the impact of the changes in ineffectiveness, compared to gains of $414 million in 2008. Mark-to-market gains on fuel hedging activities were $87 million in 2009 compared to gains of $38 million in 2008. See Notes 7 and 8 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. Mark-to-market gains on power hedging activities were $414 million in 2008 compared to losses of $253 million in 2007. Mark-to-market gains on fuel hedging activities were $38 million in 2008 compared to gains of $81 million in 2007. See Notes 7 and 8 of the Combined Notes to Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

The following table presents average electric revenues, supply costs and margins per MWh of electricity sold during 2009 as compared 2008 and 2008 compared to 2007. As set forth in the table, average electric margins are defined as average electric revenues less average electric supply costs. Generation considers average electric margins useful measures to analyze the change in profitability of electric operations between periods. Generation has included the analysis below as a complement to

the financial information provided in accordance with GAAP. However, these margins are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information Generation provides elsewhere in this report.


($/MWh)	2009		2008		2009 vs. 2008 % Change		2007		2008 vs. 2007 % Change
Average electric revenue
Electric sales to affiliates ^(a)	$	54.19	$	55.50	(2.4	)%	$	54.90	1.1	%
Wholesale and retail electric sales ^(a)		54.79		59.99	(8.7	)%		54.59	9.9	%
Total—excluding the trading portfolio		54.59		58.35	(6.4	)%		54.70	6.7	%
Average electric supply cost^{(b) (c)}—excluding the proprietary trading portfolio	$	16.39	$	19.87	(17.5	)%	$	19.54	1.7	%
Average margin—excluding the proprietary trading portfolio	$	38.20	$	38.48	(0.7	)%	$	35.16	9.4	%

(a)

$292 million of pre-tax revenue, and $2 million of a pre-tax reduction in revenue, resulting from the settlement of the ComEd swap starting in June 2008, have been excluded from Electric sales to affiliates and included in Wholesale and retail electric sales for the twelve months ended December 31, 2009 and December 31, 2008, respectively. Additionally, $88 million (1,916 GWh) and $29 million (486 GWh) of pre-tax revenue, resulting from sales to ComEd under the RFP, which started in September 2008, have been excluded from Electric sales to affiliates and included in Wholesale and retail electric sales for the twelve months ended December 31, 209 and December 31, 2008, respectively. In addition, REC sales to affiliates have been included within Wholesale and retail electric sales.

(b)	Average supply cost includes purchased power and fuel costs associated with electric sales excluding the impact of mark-to-market hedging activities. Average electric supply cost does not include fuel costs associated with retail gas sales and other sales for all periods presented.

(c)	For year 2007, excludes the net impact of the $119 million loss related to the execution of the Georgia Power PPA and costs related to the termination of the State Line PPA during 2007.

The following table presents nuclear fleet operating data for 2009, as compared to 2008 and 2007, for the Exelon-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation and certain other non-production related overhead costs. Generation considers capacity factor and production costs useful measures to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.


	2009			2008			2007
Nuclear fleet capacity factor ^(a)		93.6	%		93.9	%		94.5	%
Nuclear fleet production cost per MWh ^(a)	$	16.07		$	15.87	^(b)	$	14.46

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

(b)	Excludes the $53 million reduction in fuel expense related to uranium supply agreement non-performance settlements.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. The nuclear fleet capacity factor, which excludes Salem, decreased primarily due to a higher number of outage days. For 2009 and 2008, scheduled refueling outage days totaled 263 and 241, respectively, and non-refueling outage days totaled 78 and 59, respectively. Higher nuclear fuel costs, partially offset by lower refueling outage and other labor and contracting costs, resulted in a higher production cost per MWh during 2009 as compared to 2008.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. The nuclear fleet capacity factor decreased primarily due to a higher number of planned refueling outage days. For 2008

and 2007, refueling outage days totaled 241 and 195, respectively, while non-refueling outage days totaled 59 in both years. The lower number of net MWh generated, the impact of inflation on labor and contracting costs, higher nuclear fuel costs and the refueling outage costs associated with the higher number of refueling outage days resulted in a higher production cost per MWh during 2008 as compared to 2007.

Operating and Maintenance Expense

The changes in operating and maintenance expense for 2009 compared to 2008, consisted of the following:


	Increase (Decrease)
Impairment of certain generating assets ^(a)	$	223
Pension and non-pension postretirement benefits expense		92
Nuclear insurance credits ^(b)		28
Announced plant shutdowns ^(c)		24
Nuclear refueling outage costs, including the co-owned Salem Plant ^(d)		(46	)
Labor, other benefits, contracting and materials ^(e)		(35	)
Asset retirement obligation reduction ^(f)		(26	)
Accounts receivable reserve ^(g)		(22	)
Other		(17	)

Increase in operating and maintenance expense	$	221

(a)	Reflects the impairment of certain generating assets in 2009. See Notes 6 and 7 of the Combined Notes to Consolidated Financial Statements for further information.

(b)	Reflects the impact of the return of property and business interruption insurance premiums in 2008. No premiums were received for 2009.

(c)	Reflects severance-related and inventory write-down costs incurred in 2009 associated with the announced plant shutdowns. See Note 14 of the Combined Notes to Consolidated Financial Statements for further information.

(d)	Primarily reflects the impact of decreased planned and unplanned nuclear outage days in 2009.

(e)	Primarily reflects the impact of Exelon’s 2009 cost savings program.

(f)	Primarily reflects an increased reduction in the ARO in excess of the related ARC balances for the non-regulatory agreement units during 2009 as compared to 2008.

(g)	Reflects the impact of an increase in accounts receivable reserves recorded in 2008 as a result of Generation’s direct net exposure to Lehman Brothers Holdings Inc.

The changes in operating and maintenance expense for 2008 compared to 2007, consisted of the following:


	Increase (Decrease)
Nuclear refueling outage costs, including the co-owned Salem Plant ^(a)	$	88
Labor, other benefits, contracting and materials		74
Decommissioning-related activities ^(b)		47
Accounts receivable reserve ^(c)		22
Asset retirement obligation reduction ^(d)		19
Nuclear insurance credits ^(e)		15
New nuclear plant development costs ^(f)		(22	)
Other		20

Increase in operating and maintenance expense	$	263

(a)	Reflects a higher number of nuclear refueling outage days in 2008 compared to 2007.

(b)	Reflects an increase in the contractual elimination of income taxes associated with the decommissioning trusts funds of the former ComEd and PECO nuclear generating units (Regulatory Agreement Units).

(c)	Reflects an increase in the accounts receivable reserve recorded in 2008 as a result of Generation’s direct net exposure to Lehman Brothers Holdings Inc.

(d)	Reflects a decreased reduction in the ARO in excess of the related ARC balances for the Non-Regulatory Agreement Units and fossil units during 2008 as compared to 2007.

(e)	Reflects the impact of the return of property and business interruption insurance premiums in 2008 compared to 2007.

(f)	Reflects a reduction in costs associated with possible construction of a nuclear power plant in southeast Texas.

Depreciation and Amortization

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. For 2009 as compared to 2008, the increase in depreciation and amortization expense was a result of a change in the estimated useful lives of the plants associated with the 2009 announced shutdowns further described in Note 14 of the Combined Notes to Consolidated Financial Statements, which resulted in $32 million of accelerated depreciation. Additionally, the change in the estimated useful life of a fossil-fired power plant in 2008 resulted in $18 million higher depreciation expense in 2009. The remaining increase is primarily due to higher plant balances due to capital additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages), partially offset by the impact of the reassessment of the useful lives of several other fossil-fired facilities in 2008 and reduced depreciation associated with the generating assets impaired in 2009.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. For 2008 as compared to 2007, the increase in depreciation and amortization expense was primarily due to higher plant balances due to capital additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages), partially offset by the reassessment of the useful lives of several fossil facilities. The impact of the reassessment of the useful lives did not result in a material change to Generation’s results of operations as compared to amounts recognized in periods prior to the change.

Taxes Other Than Income

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. For 2009 as compared to 2008, the increase was primarily due to a $9 million gross receipts tax adjustment in 2008.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. For 2008 as compared to 2007, the increase was primarily due to higher payroll taxes of $11 million and higher property taxes of $8 million, partially offset by a $9 million gross receipts tax adjustment in 2008.

Interest Expense

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. For 2009 as compared to 2008, the decrease in interest expense reflects lower interest of $16 million on SNF obligations as a result of lower rates. Interest on the spent fuel obligation accrues at the 13-week Treasury Rate and is recalculated on a quarterly basis. See Note 12 of the Combined Notes to Consolidated Financial Statements for further information. Additionally, the decrease in interest expense reflects a $16 million increase in capitalized interest during 2009 as compared to 2008. These decreases in interest expense are partially offset by a $9 million increase in interest expense related to uncertain tax positions.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. For 2008 as compared to 2007, the decrease in interest expense reflected lower interest of $29 million on SNF obligations as a result of lower rates and a $24 million decrease in interest expense related to a change in the estimate of interest on uncertain tax positions, partially offset by increased interest of $27 million from higher outstanding long-term debt balances as a result of the September 2007 bond issuance.

Other, Net

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008. For 2009 as compared to 2008, the increase reflects net unrealized gains in 2009 on the NDT funds of its Non-Regulatory Agreement Units as compared to net unrealized losses in 2008. See the table below for additional information. Additionally, the increase reflects the contractual elimination of $181 million of income tax expense associated with the NDT funds of the Regulatory Agreement Units in 2009 compared to the contractual elimination of $202 million of income tax benefit in 2008. These increases are partially offset by the impacts of income in 2008 related to the termination of a gas supply guarantee and $71 million of expense related to long-term debt extinguished in the third and fourth quarter of 2009 further described in Note 9 of the Combined Notes to Consolidated Financial Statements

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007. For 2008 as compared to 2007, the decrease primarily reflects net unrealized losses in 2008 on the NDT funds of the Non-Regulatory Agreement Units due to adverse financial market conditions, the contractual elimination of income tax benefits associated with the NDT funds of the Regulatory Agreement Units, realized losses on the trust funds of the Non-Regulatory Agreement Units due to the execution of a tax planning strategy in 2008, and realized gains in 2007 on NDT fund investments of the Non-Regulatory Agreement Units associated with changes in Generation’s investment strategy, partially offset by a gain on sale of TEG and TEP in 2007.

The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in other, net for 2009, 2008 and 2007:


	2009		2008			2007
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units	$	227	$	(324	)	$	—	^(b)
Net realized gains (losses) on sale of decommissioning trust funds—Non-Regulatory Agreement Units	$	29	$	(39	)	$	64
Other-than-temporary impairment of decommissioning trust funds—Non-Regulatory Agreement Units ^(a)		n/a	$	n/a		$	(9	)

(a)

As a result of certain NRC regulations, Exelon and Generation were unable to demonstrate the ability and intent to hold the NDT fund investments through a recovery period and, accordingly, recognized any unrealized holding losses immediately. After the January 1, 2008 adoption of the fair value option, other-than-temporary impairments are no longer recognized since all changes in fair value are recognized in the Statement of Operations beginning January 1, 2008.

(b)	Unrealized gains and losses were included in accumulated OCI on Exelon’s and Generation’s Consolidated Balance Sheets prior to the January 1, 2008 adoption of the fair value option.

Effective Income Tax Rate.

Generation’s effective income tax rates for the years ended December 31, 2009, 2008 and 2007 were 40.3%, 33.4% and 40.2%, respectively. During 2008, Generation recorded tax benefits on realized and unrealized losses in its qualified NDT fund investments. The tax benefits on the realized and unrealized losses discussed above were recorded at a higher statutory tax rate than Generation’s remaining income from operations, resulting in a decreased effective income tax rate. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Results of Operations—ComEd


	2009			2008			Favorable (unfavorable) 2009 vs. 2008 variance			2007			Favorable (unfavorable) 2008 vs. 2007 variance
Operating revenues	$	5,774		$	6,136		$	(362	)	$	6,104		$	32
Purchased power expense		3,065			3,582			517			3,747			165

Revenue net of purchased power expense^(a)		2,709			2,554			155			2,357			197

Other operating expenses
Operating and maintenance		1,028			1,097			69			1,091			(6	)
Operating and maintenance for regulatory required programs		63			28			(35	)		—			(28	)
Depreciation and amortization		494			464			(30	)		440			(24	)
Taxes other than income		281			298			17			314			16

Total other operating expenses		1,866			1,887			21			1,845			(42	)

Operating income		843			667			176			512			155

Other income and deductions
Interest expense, net		(319	)		(348	)		29			(318	)		(30	)
Equity in losses of unconsolidated affiliates		—			(8	)		8			(7	)		(1	)
Other, net		79			18			61			58			(40	)

Total other income and deductions		(240	)		(338	)		98			(267	)		(71	)

Income before income taxes		603			329			274			245			84
Income taxes		229			128			(101	)		80			(48	)

Net income	$	374		$	201		$	173		$	165		$	36

(a)

ComEd evaluates its operating performance using the measure of revenue net of purchased power expense. ComEd believes that revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

Net Income

Year ended December 31, 2009 Compared to Year Ended December 31, 2008. The increase in ComEd’s net income was driven primarily by higher revenue net of purchased power expense, reflecting increased distribution rates effective September 16, 2008, partially offset by a decline in electric deliveries, primarily resulting from unfavorable weather conditions and reduced load in 2009. In addition, ComEd’s increase in net income reflects lower operating and maintenance expenses, lower interest expense, and higher interest income related to the 2009 remeasurement of uncertain income tax positions.

The reduction in operating and maintenance expense reflects Exelon’s company-wide cost savings initiative in 2009. The initiative included job reductions, for which ComEd recorded a charge for severance expense as a cost to achieve these savings. ComEd also benefited from decreased storm expenses. Operation and maintenance expense reflect increased pension and other postretirement benefits expense due to lower than expected pension and postretirement plan asset returns in 2008. In the September 2008 rate case ruling, the ICC mandated fixed asset disallowances while allowing certain regulatory assets, which were recorded as a net one-time charge in 2008.

Depreciation and amortization expenses increased due to higher plant balances and new depreciation rates effective January 1, 2009. ComEd experienced a decrease in interest expense primarily due to lower outstanding debt in 2009. ComEd also recorded higher interest income related to the remeasurement in 2009 of uncertain income tax positions.

Year ended December 31, 2008 Compared to Year Ended December 31, 2007. ComEd’s net income for 2008 compared to 2007 reflected higher revenue net of purchased power expense, primarily driven by higher transmission rates effective May 1, 2007 and June 1, 2008 and higher distribution rates effective September 16, 2008. In 2008, ComEd received a refund of Illinois Distribution Tax that also contributed to the increase in net income. These increases were partially offset by unfavorable weather, higher operating and maintenance expense, principally driven by disallowances arising from the September 2008 rate case order, higher storm costs, higher depreciation and amortization expense, and higher interest expense.

Operating Revenues Net of Purchased Power Expense

There are certain drivers to revenue that are fully offset by their impact on purchased power expense, such as commodity procurement costs and customer choice programs. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on electric revenue net of purchased power expense. See Note 2 of the Combined Notes to the Consolidated Financial Statements for information on ComEd’s electricity procurement process.

Electric revenues and purchased power expense are affected by fluctuations in customers’ purchases from competitive electric generation suppliers. All ComEd customers have the choice to purchase electricity from an alternative electric generation supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation services.

Details of ComEd’s retail customers purchasing electricity from competitive electric generation suppliers in 2009 and 2008 consisted of the following:


	2009		2008
Number of customers at period end	53,400		43,100
Percentage of total retail customers	1	%	1	%
Volume (GWh)	44,871		46,950
Percentage of total retail deliveries	52	%	51	%

The changes in ComEd’s electric revenue net of purchased power expense for 2009 compared to 2008 consisted of the following:


	Increase (Decrease)
Distribution pricing	$	214
Energy efficiency and demand response programs		34
2007 City of Chicago Settlement		10
Transmission		(26	)
Volume—delivery		(40	)
Weather—delivery		(45	)
Other		8

Total increase	$	155

Distribution pricing

The increase in retail electric revenues net of purchased power expense as a result of distribution pricing in 2009 compared to the same period in 2008, reflected the impact of the 2007 Rate Case. The ICC issued an order in the 2007 Rate Case approving a $274 million increase in ComEd’s annual revenue requirement. The order became effective September 16, 2008 resulting in increased distribution revenues in 2009 compared to 2008. See Note 2 of the Combined Notes to the Consolidated Financial Statements for additional information.

Energy efficiency and demand response programs

As a result of the Illinois Settlement Legislation, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008 and are allowed recovery of the costs of these programs from customers on a full and current basis through a reconcilable automatic adjustment clause. In 2009, ComEd recognized $59 million of revenue associated with these programs, compared to $25 million in 2008. These amounts were offset by equal amounts in operating and maintenance expense for regulatory required programs. See Note 2 and Note 19 of the Combined Notes to the Consolidated Financial Statements for additional information.

2007 City of Chicago Settlement

ComEd paid $8 million and $18 million in 2009 and 2008, respectively, under the terms of its 2007 Settlement Agreement with the City of Chicago. Payments are recorded as a reduction in revenues; therefore, the lower payment in 2009 resulted in a net increase in revenues net of purchased power expense for 2009 compared to 2008. See Note 2 of the Combined Notes to Consolidated Financial Statements for more information.

Transmission

Transmission revenues net of purchased power expense decreased primarily due to a FERC order issued in 2008, which approved incentive recovery treatment of ComEd’s largest transmission project. The cumulative recognition in 2008 of the 2007 effects of this order resulted in higher revenues in 2008 compared to 2009. This was partially offset by the impact of higher transmission rates effective June 1, 2008 and June 1, 2009, resulting from ComEd’s FERC approved formula rate. See Note 2 of the Combined Notes to the Consolidated Financial Statements for more information.

Volume—Delivery

The decrease in revenues net of purchased power expense as a result of lower delivery volume, exclusive of the effects of weather, in 2009 as compared to 2008, reflected decreased average usage per customer and fewer customers in the ComEd service territory.

Weather—Delivery

Revenues net of purchased power expense were lower in 2009 compared to 2008 due to unfavorable weather conditions. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage and delivery of electricity. Conversely, mild weather reduces demand. Degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. In ComEd’s service territory, heating degree days decreased by 4% and cooling degree days decreased by 29% in 2009 compared to the same period in 2008.

Other

Other revenues were higher in 2009 compared to 2008. Other revenues include revenues related to late payment charges, assistance provided to other utilities through mutual assistance programs and recoveries of environmental remediation costs associated with MGP sites.

The changes in ComEd’s electric revenue net of purchased power expense for 2008 compared to 2007 consisted of the following:


	Increase (Decrease)
2007 Distribution Rate Case	$	75
Transmission		54
Rate relief program		27
Energy efficiency and demand response programs		25
Wholesale contracts		6
2007 City of Chicago Settlement		5
Volume—delivery		2
Weather—delivery		(38	)
Other		41

Total increase	$	197

2007 Distribution Rate Case

The ICC issued an order in the 2007 Rate Case approving a $274 million increase in ComEd’s annual revenue requirement. The order became effective September 16, 2008 resulting in a $75 million increase in revenues for 2008 compared to 2007. See Note 2 of the Combined Notes to the Consolidated Financial Statements for more information.

Transmission

Transmission revenues net of purchased power expense increased primarily due to a FERC order issued in 2008, which approved incentive recovery treatment of ComEd’s largest transmission project. The cumulative recognition in 2008 of the 2007 effects of this order resulted in higher revenues in 2008 compared to 2007. In addition, transmission rates increased effective May 1, 2007 and June 1, 2008 resulting from ComEd’s FERC approved formula rate. See Note 2 of the Combined Notes to the Consolidated Financial Statements for more information.

Rate relief program

ComEd funded less rate relief credits to customers in 2008 compared to 2007. Credits provided to customers are recorded as a reduction to operating revenues; therefore, the reduction in credits resulted in an increase in revenues net of purchased power expense for 2008 compared to 2007. See Note 2 of the Combined Notes to the Consolidated Financial Statements for more information.

Energy efficiency and demand response programs

As a result of the Illinois Settlement Legislation, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008. During the year ended December 31, 2008,

ComEd recognized $25 million of revenue associated with these programs. This amount was offset by an equal amount of operating and maintenance expense. See Note 2 of the Combined Notes to the Consolidated Financial Statements for more information.

Wholesale Contracts

ComEd’s revenues net of purchased power expense include a $6 million increase primarily due to the expiration of certain wholesale contracts in 2007.

2007 City of Chicago Settlement

ComEd paid $18 million and $23 million in 2008 and 2007, respectively, under the terms of its 2007 settlement agreement with the City of Chicago. Payments are recorded as a reduction in revenues; therefore, the lower payment resulted in a net increase in revenues for 2008 compared to 2007. See Note 2 of the Combined Notes to Consolidated Financial Statements for more information.

Volume—Delivery

While ComEd’s delivery volumes, exclusive of the effects of weather increased slightly compared to 2007 on a full year basis, during the fourth quarter of 2008 ComEd experienced a decrease in volumes.

Weather—Delivery

Revenues net of purchased power expense were lower due to unfavorable weather conditions in 2008 compared to the same period in 2007. Cooling degree days were 25% lower for 2008 compared to 2007, partially offset by an 11% increase in heating degree days.

Operating and Maintenance Expense

The changes in operating and maintenance expense for 2009 compared to 2008, consisted of the following:


	Increase (Decrease)
Pension and non-pension postretirement benefits expense	$	51
Severance		19
Allowance for uncollectible accounts expense ^(a)		14
Injuries and damages		(1	)
Rate Relief Programs		(6	)
Corporate allocations		(7	)
Fringe benefits		(7	)
Wages and salaries		(26	)
Contracting and materials		(32	)
2007 Rate Case disallowances ^(b)		(22	)
Incremental storm-related costs		(40	)
Other		(12	)

Decrease in operating and maintenance expense	$	(69	)

(a)	The allowance for uncollectable accounts expense increased in part as a result of the current overall negative economic conditions, partially mitigated by ComEd’s increased collection activities in 2009.

(b)

In September 2008, as a result of the 2007 Rate Case order, ComEd recorded $37 million of fixed asset disallowances; $35 million was recorded as operating and maintenance expense and $2 million was recorded as depreciation expense. In addition, ComEd established regulatory assets of $13 million associated with reversing previously incurred expenses. See Note 2 of the Combined Notes to the Consolidated Financial Statements for more information.

The changes in operating and maintenance expense for 2008 compared to 2007, consisted of the following:


	Increase (Decrease)
2007 Rate Case order ^(a)	$	22
Wages and salaries		15
Allowance for uncollectible accounts expense ^(b)		12
Storm-related costs		8
Corporate allocations		6
Injuries and damages		(9	)
Contracting		(23	)
Post rate freeze period transition expenses incurred in 2007		(26	)
Other		1

Increase in operating and maintenance expense	$	6

(a)

In September 2008, as a result of the 2007 Rate Case order, ComEd recorded $37 million of fixed asset disallowances; $35 million was recorded as operating and maintenance expense and $2 million was recorded as depreciation expense. In addition, ComEd established regulatory assets of $13 million associated with reversing previously incurred operating and maintenance expenses. See Note 2 of the Combined Notes to the Consolidated Financial Statements for more information.

(b)	The allowance for uncollectible accounts expense increased during 2008 due to increased customer account charge-offs and the impact of rate relief credits that reduced this expense during 2007.

Operating and maintenance expense for regulatory required programs

Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. To fulfill a requirement of the Illinois Settlement Legislation, ComEd initiated the ICC approved energy efficiency and demand response programs in June 2008. In 2009, expenses related to energy efficiency and demand response programs and purchased power administration costs consisted of $59 million and $4 million, respectively, compared to $25 million and $3 million, respectively, for 2008. See Note 2 and Note 19 of the Combined Notes to the Consolidated Financial Statements for additional information.

Depreciation and Amortization Expense

The changes in depreciation and amortization expense for 2009 compared to 2008 and 2008 compared to 2007, consisted of the following:


	Increase (Decrease) 2009 vs. 2008			Increase (Decrease) 2008 vs. 2007
Depreciation expense associated with higher plant balances	$	25	^(a)	$	19
2007 Rate Case asset disallowances		(2	)		2
Other amortization expense		7			3

Increase in depreciation and amortization expense	$	30		$	24

(a)	Depreciation and amortization expense increased in 2009 compared to 2008 due to higher plant balances and changes to useful lives of assets based on a depreciation rate study, which became effective January 1, 2009.

Taxes Other Than Income

Year ended December 31, 2009 Compared to Year Ended December 31, 2008. Taxes other than income decreased for 2009 compared to 2008 primarily as a result of $9 million of property tax settlements recorded in 2009. These settlements will result in lower rates prospectively.

Year ended December 31, 2008 Compared to Year Ended December 31, 2007. Taxes other than income decreased for 2008 compared to 2007 primarily as a result of a $14 million refund of 2005 Illinois distribution tax received in 2008.

Interest Expense, Net

The changes in interest expense for 2009 compared to 2008 and 2008 compared to 2007 consisted of the following:


	Increase (Decrease) 2009 vs. 2008			Increase (Decrease) 2008 vs. 2007
Uncertain income tax positions remeasurement ^(a)	$	(6	)	$	—
Interest expense on debt (including financing trusts) ^{(b) (c)}		(20	)		29
Interest expense related to uncertain tax positions ^(d)		6			3
Other ^(e)		(9	)		(2	)

(Decrease) increase in interest expense, net	$	(29	)	$	30

(a)

During 2009, ComEd recorded $66 million of interest benefit associated with the remeasurement of income tax positions, specifically related to the 1999 Sale of Fossil Generating Assets, of which, $6 million was recorded as a reversal of interest expense with the remainder recorded in Other, net. See Note 10 of the Combined Notes to Consolidated Financial Statements for more information.

(b)	In 2008, interest expense included a $7 million charge to reverse previously recognized AFUDC resulting from the January 18, 2008 FERC order granting incentive treatment on ComEd’s largest transmission project.

(c)	ComEd Financing II and ComEd Transitional Funding Trust were dissolved in 2008.

(d)	During the first quarter of 2008, ComEd recorded an increase in interest expense of $6 million related to a settlement with the IRS of a research and development claim. See Note 10 of the Combined Notes of the Consolidated Financial Statements for more information.

(e)	Primarily reflects the decrease in interest for short term borrowings in 2009.

Other, Net

The changes in Other, net for 2009 compared to 2008 and 2008 compared to 2007 consisted of the following:


	Increase (Decrease) 2009 vs. 2008			Increase (Decrease) 2008 vs. 2007
Interest income related to uncertain tax positions	$	59	^(a)	$	(36	)
Gain on disposal of assets and investments		5			—
Other-than-temporary impairment of investments		(7	)		—
Other		4			(4	)

Increase (decrease) in Other, net	$	61		$	(40	)

(a)

Effective Income Tax Rate

ComEd’s effective income tax rate for the years ended December 31, 2009, 2008 and 2007 was 38.0%, 38.9% and 32.7%, respectively. The benefit recorded for the indirect cost capitalization method change in 2007 decreased the effective income tax rate for that year. See Note 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ComEd Electric Operating Statistics and Revenue Detail


Retail Deliveries (in GWh)	2009	2008	% Change 2009 vs. 2008		2007	% Change 2008 vs. 2007
Full service ^(a)
Residential	26,619	28,389	(6.2	)%	29,374	(3.4	)%
Small commercial & industrial	13,633	14,937	(8.7	)%	16,468	(9.3	)%
Large commercial & industrial	1,216	1,045	16.4	%	1,949	(46.4	)%
Public authorities & electric railroads	421	578	(27.2	)%	766	(24.5	)%

Total full service	41,889	44,949	(6.8	)%	48,557	(7.4	)%

Delivery only ^(b)
Residential	2	—	n.m		—	n.m
Small commercial & industrial	18,601	18,550	0.3	%	17,380	6.7	%
Large commercial & industrial	25,452	27,764	(8.3	)%	27,122	2.4	%
Public authorities & electric railroads	816	636	28.3	%	518	22.8	%

Total delivery only	44,871	46,950	(4.4	)%	45,020	4.3	%

Total retail deliveries	86,760	91,899	(5.6	)%	93,577	(1.8	)%

(a)	Reflects deliveries to customers purchasing electricity from ComEd.

(b)	Reflects customers electing to purchase electricity from an alternative electric generation supplier.

n.m.	Not meaningful.


Electric Revenue	2009		2008		% Change 2009 vs. 2008		2007		% Change 2008 vs. 2007
Full service ^(a)
Residential	$	3,115	$	3,284	(5.1	)%	$	3,161	3.9	%
Small commercial & industrial		1,335		1,542	(13.4	)%		1,619	(4.8	)%
Large commercial & industrial		73		90	(18.9	)%		154	(41.6	)%
Public authorities & electric railroads		44		52	(15.4	)%		67	(22.4	)%

Total full service		4,567		4,968	(8.1	)%		5,001	(0.7	)%

Delivery only ^(b)
Residential ^(c)		—		—	n.m			—	n.m
Small commercial & industrial		325		289	12.5	%		261	10.7	%
Large commercial & industrial		314		295	6.4	%		276	6.9	%
Public authorities & electric railroads		13		7	85.7	%		5	40.0	%

Total delivery only		652		591	10.3	%		542	9.0	%

Total electric retail revenues		5,219		5,559	(6.1	)%		5,543	0.3	%

Other revenue ^(d)		555		577	(3.8	)%		561	2.9	%

Total electric and other revenue	$	5,774	$	6,136	(5.9	)%	$	6,104	0.5	%

(a)	Reflects deliveries to customers purchasing electricity from ComEd, which include the cost of electricity and the cost of transmission and distribution of the electricity.

(b)	Reflects revenue under tariff rates from customers electing to purchase electricity from an alternative electric generation supplier.

(c)	There were a minimal number of residential customers being served by alternative electric generation suppliers with total activity of less than $1 million for the years 2009, 2008, 2007.

(d)	Other revenues primarily include transmission revenues from PJM. Other items also include late payment charges and mutual assistance program revenues.

n.m.	Not meaningful.

Results of Operations—PECO


	2009			2008			Favorable (unfavorable) 2009 vs. 2008 variance			2007			Favorable (unfavorable) 2008 vs. 2007 variance
Operating revenues	$	5,311		$	5,567		$	(256	)	$	5,613		$	(46	)
Purchased power expense and fuel expense		2,746			3,018			272			2,983			(35	)

Revenue net of purchased power expense ^(a) and fuel expense		2,565			2,549			16			2,630			(81	)

Other operating expenses
Operating and maintenance		640			731			91			630			(101	)
Depreciation and amortization		952			854			(98	)		773			(81	)
Taxes other than income		276			265			(11	)		280			15

Total other operating expenses		1,868			1,850			(18	)		1,683			(167	)

Operating income		697			699			(2	)		947			(248	)

Other income and deductions
Interest expense, net		(187	)		(226	)		39			(248	)		22
Equity in losses of unconsolidated affiliates		(24	)		(16	)		(8	)		(7	)		(9	)
Other, net		13			18			(5	)		45			(27	)

Total other income and deductions		(198	)		(224	)		26			(210	)		(14	)

Income before income taxes		499			475			24			737			(262	)
Income taxes		146			150			4			230			80

Net income		353			325			28			507			(182	)
Preferred security dividends		4			4			—			4			—

Net income on common stock	$	349		$	321		$	28		$	503		$	(182	)

(a)

PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

Net Income

Year ended December 31, 2009 Compared to Year Ended December 31, 2008. The increase in net income was driven primarily by increased operating revenue net of purchased power and fuel expense and decreased interest expense, which was partially offset by increased operating expenses. The increase in revenue net of purchased power and fuel expense was primarily related to increased gas distribution rates effective January 1, 2009, which were partially offset by reduced electric load.

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PECO’s operating expenses increased as a result of increased scheduled CTC amortization expense and pension and other postretirement benefits expense due to lower than expected pension and postretirement plan asset returns in 2008. The increased operating expenses were partially offset by decreased allowance for uncollectible accounts expense.

PECO also experienced a decrease in gross receipts tax expense primarily due to a rate reduction.

Year ended December 31, 2008 Compared to Year Ended December 31, 2007. PECO’s net income for 2008 compared to 2007 decreased due to lower operating revenue net of purchased power and fuel expense, reflecting unfavorable weather conditions, as well as higher operating and maintenance expenses primarily driven by an increase in the allowance for uncollectible accounts expense and increased scheduled CTC amortization partially offset by decreased interest expense.

Operating Revenues Net of Purchased Power and Fuel Expense

There are certain drivers to revenue that are fully offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and customer choice programs. Gas revenues and fuel expense are affected by fluctuations in natural gas procurement costs. PECO’s purchased natural gas cost rates charged to customers are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased natural gas and the amount included in rates in accordance with the PAPUC’s PGC. Therefore, fluctuations in natural gas procurement costs have no impact on gas revenue net of fuel expense. The average purchased gas cost rate per mmcf was $8.80, $11.31 and $10.23 for the years ended December 31, 2009, 2008 and 2007, respectively. PECO’s electric generation rates charged to customers are capped until December 31, 2010 in accordance with the 1998 restructuring settlement under the Competition Act. Under PECO’s full requirements PPA with Generation, purchased power costs are based on the rates charged to customers. Electric revenues and purchased power expense fluctuate in relation to customer class usage as each customer class is charged a different capped electric generation rate; however, there is no impact on electric revenue net of purchased power expense.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. 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. The number of retail customers purchasing energy from a competitive electric generation supplier was 21,700, 24,800 and 29,200 at December 31, 2009, 2008 and 2007, respectively, representing 1%, 2% and 2% of total retail customers, respectively.

The changes in PECO’s electric revenue net of purchased power expense and gas revenue net of fuel expense for the year ended December 31, 2009 compared to the same period in 2008 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Weather	$	(24	)	$	3		$	(21	)
Gas distribution rate increase		—			77			77
Volume		(67	)		(2	)		(69	)
Pricing		22			—			22
Other		11			(4	)		7

Total increase (decrease)	$	(58	)	$	74		$	16

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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 winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. Electric revenues net of purchased power expense were lower due to the impact of unfavorable 2009 weather conditions in PECO’s service territory and gas revenues net of fuel expense were higher due to the impact of unfavorable weather conditions in PECO’s service territory in the winter months of 2008. Heating degree days were 3% higher and cooling degree days were 8% lower. Heating degree days and cooling degrees days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business.

Gas distribution rate increase

The increase in gas revenues net of fuel expense reflected increased distribution rates effective January 1, 2009 resulting from the settlement of the 2008 gas distribution rate case.

Volume

The decrease in revenues net of purchased power and fuel expense as a result of lower delivery volume, exclusive of the effects of weather, reflected decreased electric usage per customer across all customer classes as well as decreased gas usage across the small commercial and industrial customer class.

Pricing

The increase in electric revenues net of purchased power expense as a result of pricing reflected the impact of lower PECO electric distribution rates in 2008 due to the refund of the 2007 PURTA settlement to customers. The rate change had no impact on operating income because it was offset by the amortization of the regulatory liability related to the 2007 PURTA settlement reflected in taxes other than income.

Other

The increase in other electric revenues net of purchased power expense reflected an increase in revenues associated with shifts in volume among customer classes, which resulted in a different profile of rates as different customer classes are charged different rates.

The changes in PECO’s electric revenue net of purchased power expense and gas revenue net of fuel expense for the year ended December 31, 2008 compared to the same period in 2007 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Weather	$	(48	)	$	(6	)	$	(54	)
Settlement of PJM billing dispute		(10	)		—			(10	)
Volume		14			—			14
Pricing		(29	)		—			(29	)
Transmission		(11	)		—			(11	)
Other		10			(1	)		9

Total increase (decrease)	$	(74	)	$	(7	)	$	(81	)

102

Weather

Revenues net of purchased power and fuel expense were lower due to the impact of unfavorable 2008 weather conditions in PECO’s service territory. Heating and cooling degree days were 3% and 11% lower, respectively.

Settlement of PJM Billing Dispute

PECO’s purchased power expense increased $10 million due to the impact of the favorable settlement of a PJM billing dispute with PPL during 2007.

Volume

The increase in electric revenues net of purchased power expense as a result of higher delivery volume, exclusive of the effects of weather, reflected increased electric usage per customer, primarily in the residential electric customer class and an increased number of electric customers in all customer classes.

Pricing

The decrease in electric revenues net of purchased power expense as a result of pricing reflected lower PECO electric distribution rates in 2008 due to the refund of the 2007 PURTA settlement to customers. The rate change had no impact on operating income because it was offset by the amortization of the regulatory liability related to the 2007 PURTA settlement reflected in taxes other than income.

Transmission

The decrease in electric revenues net of purchased power expense reflected decreased transmission revenue earned by PECO as a transmission owner for the use of PECO’s transmission facilities in PJM. This revenue is based on the prior year’s summer peak, and the summer peak in 2007 was lower than in 2006. Transmission expenses increased due to increased allocated costs from PJM. Transmission expenses represent wholesale transmission costs and other costs allocated by PJM, including charges for transmission stabilization, default charges and RTEP costs.

Other

The increase in other electric revenues net of purchased power expense reflected an increase in revenues associated with volume shifts among customer classes, which resulted in a different profile of rates as different customer classes are charged different rates.

Operating and Maintenance Expense

The decrease in operating and maintenance expense for 2009 compared to 2008 consisted of the following:


	Increase (Decrease)
Allowance for uncollectible accounts expense	$	(97	)
Incremental storm-related costs		(9	)
Materials and supplies		(3	)
Pension and OPEB expense		11
Wages and salaries		5
Severance		3
Other		(1	)

Decrease in operating and maintenance expense	$	(91	)

103

The increase in operating and maintenance expense for 2008 compared to 2007 consisted of the following:


	Increase (Decrease)
Allowance for uncollectible accounts expense	$	89
Wages and salaries		9
Fringe benefits		4
Contracting		1
Injuries and damages expense		(2	)

Increase in operating and maintenance expense	$	101

Allowance for uncollectible accounts expense

The decrease in allowance for uncollectible accounts expense for the year ended December 31, 2009 compared to 2008 primarily reflects improved accounts receivable aging as a result of enhancements to credit processes and increased collection and termination activities initiated in September 2008 and continuing through 2009. The credit process enhancements and increased collection and termination activities resulted in increased allowance for uncollectible accounts expense for the year ended December 31, 2008 compared to 2007, primarily due to updated reserve estimates to reflect the anticipated increases in customer account charge-offs associated with these activities as well as the further deterioration in actual and projected collections of PECO’s higher risk customer accounts receivable.

Depreciation and Amortization Expense

The increase in depreciation and amortization expense for 2009 compared to 2008 and 2008 compared to 2007 consisted of the following:


	Increase (Decrease) 2009 vs. 2008		Increase (Decrease) 2008 vs. 2007
CTC amortization ^(a)	$	90	$	78
Other		8		3

Increase in depreciation and amortization expense	$	98	$	81

(a)	The increase in PECO’s scheduled CTC amortization recorded is in accordance with its 1998 restructuring settlement under the Competition Act.

Taxes Other Than Income

The increase in taxes other than income for 2009 compared to 2008 and the decrease in 2008 compared to 2007 consisted of the following:


	Increase (Decrease) 2009 vs. 2008			Increase (Decrease) 2008 vs. 2007
PURTA amortization ^(a)	$	34		$	(36	)
Reduction of reserve related to PURTA tax appeal ^(b)		—			17
Sales and use tax		—			3
Taxes on utility revenues ^(c)		(22	)		2
Other		(1	)		(1	)

Increase (decrease) in taxes other than income	$	11		$	(15	)

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(a)

The increase was due to the impact of amortization of the regulatory liability recorded during 2008 in connection with the 2007 PURTA settlement, which began in January 2008 and was fully amortized in January 2009. The impact of the amortization on operating income in 2008 was offset by lower revenues due to a reduction in the distribution rates to refund the PURTA taxes to customers.

(b)	On March 27, 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO reduced the reserve associated with this matter.

(c)	The decrease in tax expense for 2009 compared to 2008 was due to a gross receipts tax rate reduction that became effective on January 1, 2009.

Interest Expense, Net

The decrease in interest expense, net for 2009 compared to 2008 and 2008 compared to 2007 was primarily due to a decrease in the outstanding debt balance owed to PETT, partially offset by an increase in interest expense associated with a higher amount of outstanding long-term first and refunding mortgage bonds.

Other, Net

The decrease in Other, net for 2009 compared to 2008 was primarily due to the impact of interest income recorded in 2008 related to the SSCM settlement. See Note 19 of the Combined Notes to the Consolidated Financial Statements for additional details of the components of Other, net.

The decrease in Other, net for 2008 compared to 2007 was primarily due to the impacts of interest income recorded in 2007 related to the SSCM settlement, partially offset by an increase in interest income related to uncertain income tax positions. See Note 19 of the Combined Notes to the Consolidated Financial Statements for additional details of the components of Other, net.

Effective Income Tax Rate

PECO’s effective income tax rates for the years ended December 31, 2009, 2008 and 2007 were 29.3%, 31.6% and 31.2%, respectively. See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO Electric Operating Statistics and Revenue Detail


Retail Deliveries (in GWh)	2009	2008	% Change 2009 vs. 2008		2007	% Change 2008 vs. 2007
Full service ^(a)
Residential	12,871	13,287	(3.1	)%	13,446	(1.2	)%
Small commercial & industrial	8,044	8,211	(2.0	)%	8,288	(0.9	)%
Large commercial & industrial	15,832	16,474	(3.9	)%	16,522	(0.3	)%
Public authorities & electric railroads	930	909	2.3	%	930	(2.3	)%

Total full service	37,677	38,881	(3.1	)%	39,186	(0.8	)%

Delivery only ^(b)
Residential	22	30	(26.7	)%	42	(28.6	)%
Small commercial & industrial	353	469	(24.7	)%	571	(17.9	)%
Large commercial & industrial	16	3	n.m.		14	(78.6	)%

Total delivery only	391	502	(22.1	)%	627	(19.9	)%

Total retail deliveries	38,068	39,383	(3.3	)%	39,813	(1.1	)%

105

(a)	Full service reflects deliveries to customers purchasing electricity directly from PECO.

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

n.m.	Not meaningful


Electric Revenue	2009		2008		% Change 2009 vs. 2008		2007		% Change 2008 vs. 2007
Full service ^(a)
Residential	$	1,857	$	1,916	(3.1	)%	$	1,948	(1.6	)%
Small commercial & industrial		1,015		1,028	(1.3	)%		1,042	(1.3	)%
Large commercial & industrial		1,307		1,406	(7.0	)%		1,386	1.4	%
Public authorities & electric railroads		90		87	3.4	%		89	(2.2	)%

Total full service		4,269		4,437	(3.8	)%		4,465	(0.6	)%

Delivery only ^(b)
Residential		2		2	0.0	%		4	(50.0	)%
Small commercial & industrial		19		25	(24.0	)%		30	(16.7	)%

Total delivery only		21		27	(22.2	)%		34	(20.6	)%

Total electric retail revenues		4,290		4,464	(3.9	)%		4,499	(0.8	)%

Other revenue (c)		259		282	(8.2	)%		276	2.2	%

Total electric and other revenue	$	4,549	$	4,746	(4.2	)%	$	4,775	(0.6	)%

(a)	Full service reflects deliveries to customers purchasing electricity directly from PECO, 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 electing to receive generation service from a competitive electric generation supplier, which includes a distribution charge and a CTC.

(c)	Other revenue includes 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 mmcf)	2009		2008		% Change 2009 vs. 2008		2007		% Change 2008 vs. 2007
Retail sales		57,103		56,110	1.8	%		58,968	(4.8	)%
Transportation		27,206		27,624	(1.5	)%		27,632	(0.0	)%

Total		84,309		83,734	0.7	%		86,600	(3.3	)%


Revenue	2009		2008		% Change 2009 vs. 2008		2007		% Change 2008 vs. 2007
Retail sales	$	732	$	795	(7.9	)%	$	784	1.4	%
Transportation		21		19	10.5	%		17	11.8	%
Resales and other		9		7	28.6	%		37	(81.1	)%

Total gas revenue	$	762	$	821	(7.2	)%	$	838	(2.0	)%

Liquidity and Capital Resources

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s access to external financing on reasonable terms

106

depends on its credit ratings and current overall capital market 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 unsecured revolving credit facilities with aggregate bank commitments of $957 million, $4.8 billion, $952 million and $574 million, respectively. The Registrants’ credit facilities largely extend through October 2012 for Exelon, Generation and PECO and February 2011 for ComEd. Exelon, Generation, and PECO utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. ComEd uses its credit facilities to provide for short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

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 capital improvements and 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. See Note 9 of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.

Cash Flows from Operating Activities

General

Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers. Generation’s future cash flows from operating activities may 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 the transmission and distribution of electricity and, in the case of PECO, gas distribution services to an established and diverse base of retail customers. ComEd’s and PECO’s future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.

Pension and Other Postretirement Benefits

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and Exelon’s estimated obligations under the plans. The funded status may change over time due to several factors, including contribution levels, assumed discount rates and actual and assumed rates of return on plan assets. During 2008, the unfunded status of Exelon’s plans increased significantly, primarily due to lower than expected asset returns. Exelon has continued to monitor financial market conditions and their impact on the plans during 2009. The unfunded balance of the plans decreased to $5.83 billion as of December 31, 2009 as compared to $6.38 billion at December 31, 2008. This decrease was primarily a result of a $350 million discretionary pension contribution made during the third quarter, as well as significantly improved asset returns in 2009 compared to 2008. While a decrease in discount rates and other factors resulted in an increase in the pension and other postretirement obligation, it was more than offset by the significant increase in asset values.

107

The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. Recent pension funding guidance has modified some of those elections.

On December 23, 2008, President Bush signed the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which allows the use of average assets, including expected returns (subject to certain limitations) for a 24-month period prior to the measurement date, in the determination of funding requirements, among other provisions. This option is referred to as asset smoothing. Exelon has elected to utilize asset smoothing for its largest pension plan and market value of assets for its remaining plans. These elections are expected to provide Exelon the opportunity to defer certain contributions to later years and potentially mitigate future contributions through investment market recovery.

In March and September 2009, the U.S. Treasury Department provided guidance on the selection of the corporate bond yield curve for determining the interest rate used to calculate plan liabilities and determine pension funding requirements. There are other legislative and regulatory funding relief proposals also being discussed. Exelon is monitoring the progress of these initiatives and evaluating their potential impact on funding requirements and strategies.

Management considers various factors when making funding decisions, including actuarially determined minimum contribution requirements under ERISA, as amended, and contributions required to avoid benefit restrictions for the pension plans. Regulatory requirements and the amount deductible for income tax purposes are among the factors considered in determining funding for the other postretirement benefit plans.

During September 2009, Exelon made a discretionary pension contribution of $350 million to its largest pension plan, of which Generation, ComEd and PECO contributed $154 million, $153 million and $17 million, respectively. The contribution, combined with funding elections, is expected to reduce future contribution requirements. See the “Contractual Obligations and Off-Balance Sheet Arrangements” section below for management’s estimated pension contributions.

Tax Matters

During 2008, Generation benefited from a provision in the Energy Policy Act of 2005 which allowed companies an income tax deduction for a “special transfer” of funds from a non-tax qualified NDT fund to a qualified NDT fund. As a result of interpretative guidance published by the IRS with respect to this provision in the Energy Policy Act of 2005, Generation completed a special transfer in the first quarter of 2008, which resulted in net positive cash flow of approximately $280 million in total for 2008 and 2009 combined.

In addition, Exelon, through ComEd, has taken certain tax positions to defer the tax gain on the 1999 sale of its fossil generating assets. The IRS has disallowed the deferral of the gain on this sale. As more fully described in Note 10 of the Combined Notes to Consolidated Financial Statements, a fully successful IRS challenge to Exelon’s and ComEd’s positions would accelerate income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable.

The ARRA of 2009 was enacted in the first quarter of 2009 and included an extension of the incentive from the Economic Stimulus Act of 2008 that allows companies to claim an accelerated depreciation deduction for Federal income tax purposes equal to 50% of the cost basis of certain property placed in service during 2009. Exelon reduced its tax liability by approximately $340 million as a result of this special tax depreciation provision.

108

In 2009, Exelon received approval from the IRS to change its method of accounting for repair costs associated with Generation’s power plants. The new tax method of accounting resulted in net positive cash flow of approximately $420 million for 2009. Although the IRS granted Exelon approval to change its method of accounting, the approval did not affirm the methodology used to calculate the deduction. Exelon has requested the IRS to review its methodology through its Pre-Filing Agreement program.

Given the current economic environment, state and local governments are facing increasing financial challenges, which may increase the risk of additional income tax levies, property taxes, and other taxes.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the years ending December 31, 2009 and 2008:


	2009			2008			Variance
Net income	$	2,707		$	2,737		$	(30	)
Add (subtract):
Non-cash operating activities^(a)		3,930			3,400			530
Pension and non-pension postretirement benefit contributions		(588	)		(230	)		(358	)
Income taxes		(29	)		(38	)		9
Changes in working capital and other noncurrent assets and liabilities^(b)		(82	)		(221	)		139
Option premiums received/(paid), net		(40	)		(124	)		84
Counterparty collateral, net		196			1,027			(831	)

Net cash flows provided by operations	$	6,094		$	6,551		$	(457	)

(a)

Represents depreciation, amortization and accretion, net mark-to-market gains on derivative transactions, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, and other non-cash charges.

(b)	Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

Cash flows provided by operations for 2009 and 2008 by Registrant were as follows:


	2009		2008
Exelon	$	6,094	$	6,551
Generation		3,930		4,445
ComEd		1,020		1,079
PECO		1,166		969

Changes in Exelon’s, Generation’s, ComEd’s and PECO’s cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for 2009 and 2008 were as follows:

Generation

•

During 2009 and 2008, Generation had net collections of counterparty collateral of $195 million and $1,029 million, respectively. Net collections in 2009 and 2008 were primarily due to market conditions that resulted in favorable changes to Generation’s net mark-to-market position. Depending upon whether Generation is in a net mark-to-market liability or asset position,

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collateral may be required to be posted or collected from its counterparties. This collateral may be in various forms, such as cash, which may be obtained through the issuance of commercial paper, or letters of credit.

•

During 2007, Generation, along with ComEd and other generators and utilities, reached an agreement with various representatives from the State of Illinois to address concerns about higher electric bills in Illinois. Generation committed to contributing approximately $747 million over four years. As part of the agreement, Generation contributed cash of approximately $118 million in 2009 and $274 million 2008.

•

During 2009 and 2008, Generation’s accounts receivable from ComEd for energy purchases related to its SFC, ICC-approved RFP contracts and financial swap contract (decreased) increased by ($58) million and $99 million, respectively.

•

During 2009 and 2008, Generation’s accounts receivable from PECO under the PPA increased by $48 million and $5 million, respectively.

•

During 2009 and 2008, Generation had net payments of approximately $40 million and $124 million, respectively, related to purchases and sales of options. The level of option activity in a given year may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.

ComEd

•

During the years ended December 31, 2009 and 2008, ComEd’s payables to Generation for energy purchases related to its SFC, ICC-approved RFP contracts and financial swap contract (decreased) increased by $(58) million and $99 million, respectively. During the years ended December 31, 2009 and 2008, ComEd’s payables to other energy suppliers for energy purchases (decreased) increased by $(68) million and $41 million, respectively.

PECO

•

During the years ended December 31, 2009 and 2008, PECO’s payables to Generation under the PPA increased by $48 million and $5 million, respectively.

•

During the years ended December 31, 2009 and 2008, PECO’s payables to other energy suppliers for energy purchases decreased by $43 million and $12 million, respectively. The 2009 decrease in payables to other energy suppliers is primarily due to an agreement executed in February 2009 between PECO, Generation and PJM that changed the way that PECO and Generation administer their PPA for default service.

Cash Flows used in Investing Activities

Cash flows used in investing activities for 2009 and 2008 by Registrant were as follows:


	2009			2008
Exelon	$	(3,458	)	$	(3,378	)
Generation		(2,220	)		(1,967	)
ComEd		(821	)		(958	)
PECO		(377	)		(377	)

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Capital expenditures by Registrant and business segment for 2009 and projected amounts for 2010 are as follows:


	2009		2010
Generation ^(a)	$	1,977	$	1,975
ComEd		854		935
PECO		388		500
Other^(b)		54		30

Total Exelon capital expenditures	$	3,273	$	3,440

(a)	Includes nuclear fuel.

(b)	Other primarily consists of corporate operations and BSC.

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

Generation. Approximately 43% of the projected 2010 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Included in the projected 2010 capital expenditures are a series of planned power uprates across the company’s nuclear fleet. See “EXELON CORPORATION—Executive Overview,” for more information on nuclear uprates.

ComEd and PECO. Approximately 70% and 84% of the projected 2010 capital expenditures at ComEd and PECO, respectively, are for continuing projects to maintain and improve company operations, including enhancing reliability and adding capacity to the transmission and distribution systems. The remaining amounts are for capital additions to support new business, customer growth and AMI and Smart Grid technologies. PECO’s projected 2010 capital expenditures do not include estimated costs for transmission system reliability upgrades that could be required by PJM related to Generation’s announced plant retirements. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information. ComEd and PECO are each continuing to evaluate their total capital spending requirements. ComEd and PECO anticipate that they will fund their capital expenditures with internally generated funds and borrowings.

Cash Flows from Financing Activities

Cash flows used in financing activities for 2009 and 2008 by Registrant were as follows:


	2009			2008
Exelon	$	(1,897	)	$	(2,213	)
Generation		(1,746	)		(1,470	)
ComEd		(155	)		(161	)
PECO		(525	)		(587	)

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Debt. Debt activity for 2009 and 2008 by Registrant was as follows:


Company	Issuance of long-term debt in 2009	Use of proceeds
Generation	$46 million of 3-year term rate Pollution Control Notes at 5.00% with a final maturity of December 1, 2042	Used to refinance $46 million of unenhanced tax-exempt variable rate debt that was repurchased in February 23, 2009 ^(a)

Generation	$1.5 billion of Senior Notes, consisting of $600 million Senior Notes, 5.20% due October 1, 2019 and $900 million Senior Notes, 6.25% due October 1, 2039	Used to finance the purchase and optional redemption of Generation’s 6.95% bonds due 2011 and for general corporate purposes, including a distribution to Exelon to fund the purchase and optional redemption of Exelon’s 6.75% Notes due 2011 and to fund Generation’s September 2009 repurchase of variable-rate long-term tax-exempt debt. The distributions were used to finance the purchase and optional redemption of Exelon’s 6.75% bonds due 2011.

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 D, due March 1, 2020 ^(b)	Used to repay credit facility borrowings incurred to repurchase bonds ^(c)

ComEd	$91 million tax-exempt variable rate First Mortgage Bonds, Series 2008 F, due March 1, 2017 ^(b)	Used to repay credit facility borrowings incurred to repurchase bonds ^(c)

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 E, due May 1, 2021 ^(b)	Used to repay credit facility borrowings incurred to repurchase bonds ^(a)

PECO	$250 million of First and Refunding Mortgage Bonds, 5.00% due October 1, 2014	Used to refinance short-term debt and for other general corporate purposes

(a)	Repurchase due to failed remarketing.

(b)	Remarketed in May 2009 with letter of credit issued under credit facility.

(c)	Repurchase required due to expiration of existing letter of credit.

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Company	Issuance of long-term debt during the 2008	Use of proceeds
ComEd	$450 million of First Mortgage 6.45% Bonds, Series 107, due January 15, 2038	Used to retire $295 million of First Mortgage Bonds, Series 99, to call and refinance $155 million of trust preferred securities and for other general corporate purposes.

ComEd	$700 million of First Mortgage 5.80% Bonds, Series 108, due March 15, 2018	Used to repay a portion of borrowings under ComEd’s revolving credit facility, to provide for the retirement at scheduled maturity in May 2008 of $120 million of First Mortgage bonds, Series 83, and for general corporate purposes.

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 D, due March 1, 2020 ^(a)^(b)	Used to refinance $50 million tax-exempt variable auction-rate pollution control bonds secured by First Mortgage Bonds, Series 2003 C, due March 1, 2020

ComEd	$91 million tax-exempt variable rate First Mortgage Bonds, Series 2008 F, due March 1, 2017 ^(a)(b)	Used to refinance $91 million tax-exempt variable auction-rate pollution control bonds secured by First Mortgage Bonds, Series 2005, due March 1, 2017

ComEd	$50 million tax-exempt variable rate First Mortgage Bonds, Series 2008 E, due May 1, 2021 ^(a)(b)	Used to refinance a portion of the outstanding tax-exempt variable auction-rate pollution control bonds secured by First Mortgage Bonds, Series 2003, 2003 B and 2003 D, due May 15, 2017, November 1, 2019 and January 15, 2014

PECO	$150 million of First and Refunding Mortgage Bonds, 4.00% due December 1, 2012 ^(c)	Used to refinance First and Refunding Mortgage Bonds, variable rate due December 1, 2012

PECO	$500 million of First and Refunding Mortgage Bonds, 5.35% due March 1, 2018	Used to refinance commercial paper and for other general corporate purposes.

PECO	$300 million of First and Refunding Mortgage Bonds, 5.60% Series due October 15, 2013	Used to refinance short-term debt

(a)	First Mortgage Bonds issued under the ComEd mortgage indenture to secure variable weekly-rate tax-exempt pollution control bonds that were issued to refinance variable auction-rate tax-exempt pollution control bonds.

(b)

During the second quarter of 2008, ComEd established a $216 million letter of credit facility, of which $194 million was used to provide credit enhancement to variable-rate tax exempt bonds including $3 million of accrued interest. That facility expired on May 9, 2009, and the letters of credit are no longer outstanding.

(c)	First and Refunding Mortgage Bonds issued under the PECO mortgage indenture to secure tax-exempt pollution control bonds and notes that were issued to refinance auction-rate tax-exempt pollution control bonds.

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Company		Retirement of long-term debt in 2009

Exelon Corporate		$500 million of 6.75% Senior Notes due May 1, 2011

Generation		$700 million of 6.95% Senior Notes due June 15, 2011

Generation		$46 million of Pollution Control Notes with variable interest rates, due December 1, 2042 ^(a)

Generation		$51 million of Pollution Control Notes with variable interest rates, due April 1, 2021

Generation		$39 million of Pollution Control Notes with variable interest rates, due April 1, 2021

Generation		$30 million of Pollution Control Notes with variable interest rates, due December 1, 2029

Generation		$92 million of Pollution Control Notes with variable interest rates, due October 1, 2030

Generation		$69 million of Pollution Control Notes with variable interest rates, due October 1, 2030

Generation		$14 million of Pollution Control Notes with variable interest rates, due October 1, 2034

Generation		$13 million of Pollution Control Notes with variable interest rates, due October 1, 2034

Generation		$10 million of 6.33% notes payable, due August 8, 2009

Generation		$1 million scheduled payments of 7.83% Kennett Square capital lease until September 20, 2020

ComEd		$91 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 F, due March 1, 2017 ^(b)

ComEd		$50 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 D, due March 1, 2020 ^(b)

ComEd		$50 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 E, due May 1, 2021 ^(c)

ComEd		$16 million of 5.70% First Mortgage Bonds, Series 1994 B, due January 15, 2009

ComEd		$1 million of 4.625-4.75% sinking fund debentures, due at various dates

PECO		$319 million of 7.65% PETT Transition Bonds, due September 1, 2009

PECO		$390 million of 6.52% PETT Transition Bonds, due September 1, 2010

(a)	Repurchased due to a failed remarketing and remarketed in February 2009.

(b)	First Mortgage Bonds issued under the ComEd mortgage indenture to secure variable weekly-rate tax-exempt pollution controls bonds. Repurchased due to expiration of existing letter of credit and remarketed in May 2009.

(c)	First Mortgage Bonds issued under the ComEd mortgage indenture to secure variable weekly-rate tax-exempt pollution controls bonds. Repurchased due to a failed remarketing and remarketed in May 2009.

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Company		Retirement of long-term debt in 2008
Exelon Corporate		$21 million of 6.00-8.00% notes payable for investments in synthetic fuel-producing facilities, due at various dates

Generation		$10 million scheduled payments of 6.33% notes payable until August 8, 2009

Generation		$3 million scheduled payments of 7.83% Kennett Square Capital Lease until September 20, 2020

ComEd		$295 million of 3.70% First Mortgage Bonds, Series 99 due February 1, 2008

ComEd		$274 million of 5.74% ComEd Transitional Funding Trust, due December 25, 2008

ComEd		$155 million of 8.50% Subordinated Debentures of ComEd Financing II, due January 15, 2027

ComEd		$120 million of 8.00% First Mortgage Bonds, Series 83 due May 15, 2008

ComEd		$100 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2002, due April 15, 2013 ^(a)

ComEd		$91 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2005, due March 1, 2017 ^(a)

ComEd		$50 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2003 C, due March 1, 2020 ^(a)

ComEd		$42 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2003 B, due November 1, 2019^(a)

ComEd		$40 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2003, due May 15, 2017 ^(a)

ComEd		$20 million tax-exempt variable auction-rate First Mortgage Bonds, Series 2003 D, due January 15, 2014 ^(a)

ComEd		$2 million of 3.875-4.75% Sinking fund debentures due at various dates

PECO		$50 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 ^(b)

PECO		$50 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 ^(b)

PECO		$50 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 ^(b)

PECO		$4 million First and Refunding Mortgage Bonds, variable rate due December 1, 2012 ^(b)

PECO		$450 million of 3.5% First and Refunding Mortgage Bonds, due May 1, 2008

PECO		$207 million of 6.13% PETT Transition Bonds, due September 1, 2008

PECO		$369 million of 7.625% PETT Transition Bonds, due March 1, 2009

PECO		$33 million of 7.65% PETT Transition Bonds, due September 1, 2009

(a)	First Mortgage Bonds issued under the ComEd mortgage indenture to secure variable auction-rate tax-exempt pollution control bonds.

(b)	First and Refunding Mortgage Bonds issued under the PECO mortgage indenture to secure tax-exempt pollution control bonds and notes that were issued to refinance auction rate tax-exempt pollution control bonds.

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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.

Dividends. Cash dividend payments and distributions during 2009 and 2008 by Registrant were as follows:


	2009		2008
Exelon	$	1,385	$	1,335
Generation		2,276		1,545
ComEd		240		—
PECO		316		484

On January 26, 2010, the Exelon Board of Directors declared a quarterly dividend of $0.525 per share on Exelon’s common stock, which is payable on March 10, 2010 to shareholders of record at the end of the day on February 16, 2010.

Share Repurchases. During 2008, Exelon purchased $500 million of common stock under Exelon’s accelerated share repurchase program, including the impact of the settlement of a forward contract indexed to Exelon’s own common stock.

Short-Term Borrowings. During 2009, Exelon and PECO repaid $151 million and $95 million of commercial paper, respectively. During 2009, ComEd incurred $95 million of outstanding borrowings under its credit agreement. During 2008, Exelon and PECO repaid $95 million and $151 million, net, of commercial paper, respectively. During 2008, ComEd repaid $310 million of outstanding borrowings under its credit agreement.

Retirement of Long-Term Debt to Financing Affiliates. Retirement of long-term debt to financing affiliates during 2009 and 2008 by Registrant were as follows:


	2009		2008
Exelon	$	709	$	1,038
ComEd		—		429
PECO		709		609

Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during 2009 and 2008 by Registrant were as follows:

(a)	$320 million and $284 million for the twelve months ended December 31, 2009 and 2008, respectively, reflect payments received to reduce the receivable from parent.

Other. Other significant financing activities for Exelon for 2009 and 2008 were as follows:

•

Exelon received proceeds from employee stock plans of $42 million and $130 million during 2009 and 2008, respectively.

•

Exelon’s other financing activities during 2009 and 2008 include $5 million and $60 million, respectively, of excess tax benefits, which represent the tax deduction in excess of the tax benefit related to compensation cost recognized for stock options exercised.

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Credit Matters

Recent Market Conditions

The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $7.3 billion in aggregate total commitments of which $6.7 billion was available as of December 31, 2009, and of which no financial institution has more than 10% of the aggregate commitments for Exelon, Generation and PECO and 12% for ComEd. Generation also has additional letter of credit facilities that will expire in the second quarter of 2010, which are used to enhance variable rate long-term tax-exempt debt totaling $213 million. Generation intends to extend or replace the expiring letters of credit with new letters of credit at reasonable terms or remarket the bonds with an interest rate term not requiring letter of credit support. If Generation is unable to remarket these bonds at reasonable terms, Generation will repurchase them. Exelon, Generation and PECO had access to the commercial paper market during 2009 and they were able to fund their short-term liquidity needs with commercial paper at favorable rates compared to 2008, when necessary. ComEd utilized its credit facility to fund its short-term liquidity needs and provide credit enhancement for $191 million of variable rate tax-exempt bonds. Due to an upgrade in ComEd’s commercial paper rating on July 22, 2009 and improvements in the commercial paper market, ComEd is expected to be able to access the commercial paper market as an additional source of liquidity. However, ComEd did not issue commercial paper in 2009 due to more favorable rates on credit facility draws. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A Risk Factors for further information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operations, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of December 31, 2009, it would have been required to provide incremental collateral of approximately $880 million, which is well within its current available credit facility capacities of approximately $4.7 billion. The $880 million includes $673 million of collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payable and receivables, net of the contractual right of offset under master netting agreements and $207 million of financial assurances that Generation would be required to provide NEIL related to annual retrospective premium obligations. If ComEd lost its investment grade credit rating as of December 31, 2009, it would have been required to provide incremental collateral of approximately $207 million, which is well within its current available credit facility capacity of approximately $546 million. If PECO lost its investment grade credit rating as of December 31, 2009, it would have been required to provide collateral of $5 million pursuant to PJM’s credit policy and could have been required to provide collateral of approximately $49 million related to its natural gas procurement contracts, which is well within PECO’s current available credit facility capacity of $564 million.

Exelon Credit Facilities

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool, and ComEd meets its short-term liquidity requirements primarily through borrowings under its credit facility. While short-term borrowing costs have not been significant to date, further uncertainty in the credit markets may result in increased costs for commercial paper borrowings. Continued uncertainty in the credit markets

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could limit the ability of the Registrants to issue commercial paper, which may increase their reliance on their respective revolving credit agreements for short-term liquidity purposes. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 9 of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

ComEd’s $952 million credit facility agreement expires on February 16, 2011. ComEd expects to extend or replace that facility during 2010 and intends to increase the available commitments to total $1 billion.

On October 23, 2009, Exelon entered into new credit facility agreements totaling $67 million with minority and community banks located primarily within its service territory. The credit agreements were for Generation, ComEd and PECO in the amounts of $7 million, $30 million and $30 million, respectively. These agreements are solely utilized for issuing letters of credit. As of December 31, 2009, Generation, ComEd and PECO had issued letters of credit under these agreements totaling $5 million, $24 million and $29 million, respectively.

The following table reflects the Registrants’ commercial paper programs and revolving credit agreements at December 31, 2009.


Commercial Paper Programs
Commercial Paper Issuer	Maximum Program Size ^(a)		Outstanding Commercial Paper at December 31, 2009		Average Interest Rate on Commercial Paper Borrowings for the twelve months ended December 31, 2009
Exelon Corporate	$	957	$	—	0.72	%
Generation		4,834		—	—
ComEd ^(b)		952		—	—
PECO		574		—	0.67	%

Total	$	7,317	$	—	0.71	%

(a)	Equals aggregate bank commitments under revolving credit agreements.

(b)

Prior to July 22, 2009, ComEd was unable to access the commercial paper market given the market environment. On July 22, 2009, ComEd’s commercial paper rating was upgraded giving it limited access to the commercial paper market. However, ComEd did not issue commercial paper due to more favorable rates on credit facility draws.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit agreement, a Registrant can not issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement.


Revolving Credit Agreements
Borrower	Aggregate Bank Commitment ^(a)		Outstanding Borrowings/ Facility Draws		Outstanding Letters of Credit		Available Capacity under Revolving Credit Agreements as of December 31, 2009		Average Interest Rate on Borrowings for twelve months ended December 31, 2009
Exelon Corporate	$	957	$	—	$	5	$	952	—
Generation		4,834		—		167		4,667	—
ComEd		952		155		251		546	0.79	%
PECO		574		—		10		564	—

Total	$	7,317	$	155	$	433	$	6,729	0.79	%

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(a)	Excludes $67 million of credit facility agreements arranged with minority and community banks in October 2009 which are solely utilized to issue letters of credit and expire on October 23, 2010.

Interest rates on advances under the credit facilities are based on either prime or the 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 162.5 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 interest coverage ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and interest on nonrecourse debt. The following table summarizes the minimum thresholds reflected in the credit agreements for the twelve months ended December 31, 2009:


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

At December 31, 2009, the interest coverage ratios at the Registrants were as follows:


	Exelon	Generation	ComEd	PECO
Interest coverage ratio	13.97	35.65	5.52	5.65

An event of default under any Registrant’s credit facility will not constitute an event of default under any of the other Registrants’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or interest on any indebtedness having a principal amount in excess of $100 million in the aggregate by Generation (including Generation’s credit facility) will constitute an event of default under the Exelon credit facility.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets may depend on the securities ratings of the entity that is accessing the capital markets.

Listed below are the Registrants’ securities ratings as of December 31, 2009.


	Securities	Moody’s	S&P	Fitch
Exelon	Senior unsecured debt	Baa1	BBB-	BBB+
	Commercial paper	P2	A2	F2
Generation	Senior unsecured debt	A3	BBB	BBB+
	Commercial paper	P2	A2	F2
ComEd	Senior unsecured debt	Baa3	BBB	BBB-
	Senior secured debt	Baa1	A-	BBB
	Commercial paper	P3	A2	B
PECO	Senior unsecured debt	A3	BBB	A-
	Senior secured debt	A2	A-	A
	Commercial paper	P2	A2	F2
	Transition bonds^(a)	Aaa	AAA	AAA

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

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None of the Registrants’ borrowings are subject to default or prepayment as a result of a downgrading of securities although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

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.

On July 21, 2009, following Exelon’s termination of efforts to acquire NRG, Fitch affirmed Exelon’s and Generation’s current ratings and removed both Registrants from Ratings Watch Negative. Both Registrants were assigned a Stable ratings outlook. On July 22, 2009, S&P affirmed the ratings for Exelon, Generation and PECO and removed each Registrant from CreditWatch Negative. S&P also raised ComEd’s corporate credit rating to BBB from BBB-, its senior secured rating to A- from BBB+, its senior unsecured rating to BBB from BBB-, and its short-term rating to A2 from A3. S&P also removed ComEd’s ratings from CreditWatch Negative. The outlook for all ratings is Stable. On July 23, 2009, Moody’s confirmed Exelon’s and Generation’s current ratings and PECO’s long-term debt rating. The outlook for Exelon’s and Generation’s debt rating is Stable. PECO’s long-term debt rating was placed on Negative outlook and its short-term rating was downgraded to P2 from P1.

On August 3, 2009, Moody’s changed its methodology widening the notching between most senior secured debt ratings and senior unsecured debt ratings of investment grade regulated utilities. As a result, ComEd’s senior secured ratings increased to Baa1 from Baa2.

On January 25, 2010, Fitch upgraded ComEd’s senior secured debt ratings to BBB+ from BBB and its senior unsecured debt ratings to BBB from BBB-. ComEd’s commercial paper rating increased to F3 from B. Fitch also affirmed the ratings of Exelon, Generation and PECO and their ratings outlook as Stable. Fitch cited ComEd’s financial improvement over the past year and a more settled regulatory and legislative environment in Illinois as contributing factors for the upgrade.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contract law, if the Registrants are downgraded by a credit rating agency, 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, which could include the posting of collateral. Refer to Note 8 of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

Other Credit Matters

Capital Structure

At December 31, 2009, the capital structures of the Registrants consisted of the following:


	Exelon Consolidated		Generation		ComEd		PECO ^(a)
Long-term debt	46	%	35	%	39	%	40	%
Long-term debt to affiliates ^(b)	3		—		2		11
Common equity	50		—		58		47
Member’s equity	—		65		—		—
Preferred securities	—		—		—		2
Commercial paper and notes payable	1		—		1		—

(a)

As of December 31, 2009, PECO’s capital structure, excluding the impacts of the deduction from shareholders’ equity of the $180 million receivable from Exelon (which amount is deducted for GAAP purposes as reflected in the table above) would consist of 48% common equity, 2% preferred securities and 50% long-term debt, including long-term debt to unconsolidated affiliates.

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(b)

Includes approximately $805 million, $206 million and $599 million owed to unconsolidated affiliates of Exelon, ComEd and PECO, respectively, that qualify as special purpose entities under the applicable authoritative guidance. These special purpose entities were created for the sole purposes of issuing transition bonds to securitize intangible transition property consisting of CTCs of PECO or mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 1 of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. As of January 10, 2006, ComEd voluntarily suspended its participation in the money pool. Generation, PECO, and BSC may participate in the intercompany money pool as lenders and borrowers, and Exelon may participate as a lender. 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 2009 are described in the following table in addition to the net contribution or borrowing as of December 31, 2009:


	Maximum Contributed		Maximum Borrowed		December 31, 2009 Contributed (Borrowed)
Generation	$	138	$	—	$	—
PECO		106		—		—
BSC		—		140		(15	)
Exelon Corporate		103		N/A		15

Shelf Registrations

The Registrants filed automatic shelf registration statements that are not required to specify the amount of securities to be offered thereon. As of December 31, 2009, the Registrants each had current shelf registration statements for the sale of unspecified amounts of securities that were effective with the SEC. The ability of each Registrant 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, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations

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. As of December 31, 2009, ComEd had $389 million in long-term debt refinancing authority from the ICC and $399 million in new money long-term debt financing authority. As of December 31, 2009, PECO had $1.9 billion in long-term debt financing authority from the PAPUC.

FERC has financing jurisdiction over ComEd’s and PECO’s short-term financings and all of Generation’s financings. As of December 31, 2009, ComEd and PECO had short-term financing authority from FERC that expires on December 31, 2011 of $2.5 billion and $1.5 billion, respectively. Generation currently has blanket financing authority that it received from FERC in connection with its market-based rate authority. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional information.

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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. The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” In addition, 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. At December 31, 2009, Exelon had retained earnings of $8,134 million, including Generation’s undistributed earnings of $2,169 million, ComEd’s retained earnings of $304 million consisting of retained earnings appropriated for future dividends of $1,943 million partially offset by $1,639 million of unappropriated retained deficit, and PECO’s retained earnings of $426 million. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding fund transfer restrictions.

Investments in Synthetic Fuel-Producing Facilities

Exelon, through three separate wholly owned subsidiaries, owned interests in two limited liability companies and one limited partnership that owned synthetic fuel-producing facilities. Prior to December 31, 2007, Section 45K (formerly Section 29) of the IRC provided tax credits for the sale of synthetic fuel produced from coal. The ability to earn these synthetic fuel tax credits expired on December 31, 2007 and, as such, the synthetic fuel-producing facilities that Exelon had interests in ceased operations on or before December 31, 2007.

In March 2008, the IRS published the 2007 Oil Reference Price which resulted in a 67% phase-out of tax credits for calendar year 2007 that reduced Exelon’s earned after-tax credits of $258 million to $85 million for the year ended December 31, 2007. Exelon generated approximately $220 million of cash over the life of these investments. As a result of the phase-out of tax credits in 2008 and the timing of the realization of tax benefits earned in prior years, Exelon collected approximately $200 million of cash in 2008, which includes $44 million collected in the first quarter of 2008 related to the settlement of derivatives that were entered into in the normal course of trading operations in 2005 to economically hedge a portion of the exposure to a phase-out of the tax credits.

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Contractual Obligations and Off-Balance Sheet Arrangements

Exelon

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


	Total		Payment due within						Due 2015 and beyond		All Other
	Total		2010		2011- 2012		2013- 2014		Due 2015 and beyond		All Other
Long-term debt ^(a)	$	12,428	$	1,052	$	1,422	$	1,319	$	8,635	$	—
Interest payments on long-term debt ^(b)		8,457		666		1,195		1,019		5,577		—
Liability and interest for uncertain tax positions ^(c)		372		1		—		—		—		371
Capital leases		38		2		5		6		25		—
Operating leases		713		67		130		111		405		—
Purchase power obligations ^(d)		2,433		396		636		296		1,105		—
Fuel purchase agreements		10,679		1,237		2,335		2,073		5,034		—
Other purchase obligations ^(e)		1,128		570		399		148		11		—
City of Chicago agreement—2003 ^(f)		18		6		12		—		—		—
Spent nuclear fuel obligation		1,017		—		—		—		1,017		—
Pension minimum funding requirement ^(g)		3,596		243		894		1,658		801		—
Other postretirement benefits minimum funding requirement ^(h)		228		48		93		87		—		—

Total contractual obligations	$	41,107	$	4,288	$	7,121	$	6,717	$	22,610	$	371

(a)	Includes $415 million and $390 million due in 2010 and thereafter, respectively, to ComEd and PECO financing trusts.

(b)

Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2009 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, 2009. Includes estimated interest payments due to ComEd and PECO financing trusts.

(c)

As of December 31, 2009, Exelon’s liability for uncertain tax positions and related net interest payable were $371 million and $0 million, respectively. Exelon was unable to reasonably estimate the timing of liability and interest payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. Exelon has other unrecognized tax positions that were not recorded on the Consolidated Balance Sheet in accordance with authoritative guidance. See Note 10 of the Combined Notes to Consolidated Financial Statements for further information regarding unrecognized tax positions.

(d)

Net capacity purchases include PPAs and other capacity contracts that are accounted for as operating leases. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2009. Expected payments include certain capacity charges that are contingent on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. These obligations do not include ComEd’s SFCs as these contracts do not require purchases of fixed or minimum quantities. See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements.

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

(f)

In 2003, ComEd entered separate agreements with the City of Chicago and with Midwest Generation. Under the terms of the agreements, ComEd will pay the City of 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.

(g)

These amounts represent Exelon’s estimated minimum pension contributions to its qualified plans required under ERISA and the Pension Protection Act of 2006 as well as discretionary contributions necessary to avoid benefit restrictions. These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contributions for years after 2015 are currently not reliably estimable. Exelon may choose to make additional discretionary contributions.

(h)

These amounts represent estimated minimum other postretirement benefit contributions required under a PAPUC rate order. These minimum contributions represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2014 are currently not reliably estimable. Exelon may contribute more than the minimum funding requirements; however, these amounts are not included above as such amounts are discretionary.

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Exelon’s commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2010		2011- 2012		2013- 2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	297	$	289	$	8	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(b)		14		11		3		—		—
Surety bonds ^(c)		76		7		—		—		69
Performance guarantees ^(d)		96		—		—		95		1
Energy marketing contract guarantees ^(e)		218		193		25		—		—
Nuclear insurance premiums ^(f)		2,204		—		—		—		2,204
Lease guarantees ^(g)		125		—		—		15		110
2007 City of Chicago Settlement ^(h)		6		3		3		—		—
Midwest Generation Capacity Reservation Agreement guarantee ⁽ⁱ⁾		10		4		6		—		—
Rate relief commitments—settlement legislation ^(j)		25		25		—		—		—
Construction commitments ^(k)		196		51		68		77		—

Total commitments	$	3,267	$	583	$	113	$	187	$	2,384

(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, 2009, guarantees of $9 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 amounts of the floating-rate pollution control bonds of $213 million at Generation and $191 million at ComEd are 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 with unaffiliated third parties.

(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 as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional details on Generation’s nuclear insurance premiums.

(g)	Lease guarantees—Guarantees issued to ensure payments on building leases.

(h)

2007 City of Chicago Settlement—In December 2007, ComEd entered into an agreement with the City of Chicago. Under the terms of the agreement, ComEd will pay $55 million over six years, of which $8 million, $18 million and $23 million was paid in December 2009, 2008 and 2007, respectively. See Note 2 of the Combined Notes to Consolidated Financial Statements for additional details on the 2007 City of Chicago Settlement.

(i)

Midwest Generation Capacity Reservation Agreement guarantee—In connection with ComEd’s agreement with the City of Chicago entered into on February 20, 2003, Midwest Generation assumed from the City of Chicago a Capacity Reservation Agreement that the City of Chicago had entered into with Calumet Energy Team, LLC. ComEd has agreed to reimburse the City of Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement.

(j)	See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional detail on Generation’s and ComEd’s rate relief commitments.

(k)	See Note 18 of the Combined Notes to Consolidated Financial Statements for additional detail on ComEd’s and PECO’s construction commitments.

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Generation

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


(in millions)	Total		Payment due within						Due 2015 and beyond		All Other
(in millions)	Total		2010		2011- 2012		2013- 2014		Due 2015 and beyond		All Other
Long-term debt	$	2,959	$	24	$	—	$	500	$	2,435	$	—
Interest payments on long-term debt ^(a)		2,515		161		321		295		1,738		—
Liability and interest for uncertain tax positions ^(b)		117		1		—		—		—		116
Capital leases		38		2		5		6		25		—
Operating leases		425		27		52		48		298		—
Purchase power obligations ^(c)		2,433		396		636		296		1,105		—
Fuel purchase agreements		10,105		1,085		2,162		1,950		4,908		—
Other purchase obligations ^(d)		636		263		257		105		11		—
Spent nuclear fuel obligation		1,017		—		—		—		1,017		—

Total contractual obligations	$	20,245	$	1,959	$	3,433	$	3,200	$	11,537	$	116

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2009 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, 2009.

(b)

As of December 31, 2009, Generation’s liability for uncertain tax positions and related net interest payable were $100 million and $17 million, respectively. Generation was unable to reasonably estimate the timing of liability and interest payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

(c)

Net capacity purchases include PPAs and other capacity contracts that are accounted for as operating leases. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2009. Expected payments include certain capacity charges that are contingent on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. See Note 18 of the Combined Notes to Consolidated Financial Statements.

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

Generation’s commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011- 2012		2013- 2014		2015 and beyond
Letters of credit (non-debt) ^(a)(b)	$	172	$	172	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(c)		11		11		—		—		—
Surety bonds ^(d)		3		—		—		—		3
Performance guarantees ^(e)		96		—		—		95		1
Energy marketing contract guarantees ^(f)		218		193		25		—		—
Nuclear insurance premiums ^(g)		2,204		—		—		—		2,204
Rate relief commitments—settlement legislation ^(h)		24		24		—		—		—

Total commitments	$	2,728	$	400	$	25	$	95	$	2,208

(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 $8 million have been issued to provide support for certain letters of credit as required by third parties.

(b)	The amount includes letters of credit that are posted to ComEd related to the Illinois procurement auction.

(c)

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 $213 million is reflected in long-term debt in Generation’s Consolidated Balance Sheet.

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(d)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(e)	Performance guarantees—Guarantees issued to ensure execution under specific contracts with unaffiliated third parties.

(f)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts.

(g)

(h)	See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional detail on Generation’s rate relief commitments.

Mystic Development, LLC (Mystic), a former affiliate of Exelon New England, had 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 were indexed to the New England gas markets. Exelon New England had 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 the authoritative guidance for guarantees, approximately $13 million was included as a liability within Exelon’s and Generation’s Consolidated Balance Sheets as of December 31, 2007 related to this guarantee. In April 2008, Distrigas, Exelon New England and Mystic entered into agreements that terminated the guarantee, which resulted in Generation’s elimination of the guarantee liability and the recognition of $13 million of income.

Generation has an obligation to decommission its nuclear power plants. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. During 2008, the value of the NDT funds declined significantly due to unrealized losses as a result of adverse financial market conditions. Despite this decline in value, Generation believes that the NDT funds for the nuclear generating stations formerly owned by ComEd, PECO and AmerGen, the expected earnings thereon and, in the case of the former PECO stations, the amounts collected from PECO’s customers will ultimately be sufficient to fully fund Generation’s decommissioning obligations for its nuclear generating stations in accordance with NRC regulations. However, NRC minimum funding requirements may require Generation to take steps to address the funded status of the NDT funds. Generation is required to provide to the NRC a biennial report by unit (annually for Generation’s five units that have been retired or are within five years of the current approved license life) addressing Generation’s ability to meet the NRC-estimated funding levels. Depending on the value of the NDT funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the NDT funds, which could be significant, to ensure that the NDTs are adequately funded and that NRC minimum funding requirements are met. See Note 11 of the Combined Notes to Consolidated Financial Statements for a further discussion of matters regarding the adequacy of Generation’s NDT funds to meet its decommissioning obligations, the obligations imposed on Generation related to the potential excess or shortfall of NDT funds, the impact on Generation’s accounting for its former ComEd units as a result of a shortfall of NDT funds and other matters related to Generation’s NDT funds and decommissioning obligations.

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ComEd

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


	Total		Payment due within						Due 2015 and beyond		All Other
	Total		2010		2011- 2012		2013- 2014		Due 2015 and beyond		All Other
Long-term debt ^(a)	$	4,944	$	213	$	797	$	269	$	3,665	$	—
Interest payments on long-term debt ^(b)		3,473		280		506		423		2,264		—
Liability and interest for uncertain tax positions ^(c)		279		—		—		—		—		279
Operating leases		95		17		32		26		20		—
2003 City of Chicago agreement ^(d)		18		6		12		—		—		—
Electric supply procurement		645		615		30		—		—		—
REC purchase commitments		8		8		—		—		—		—
Other purchase obligations ^(e)		115		99		16		—		—		—

Total contractual obligations	$	9,577	$	1,238	$	1,393	$	718	$	5,949	$	279

(a)	Includes $206 million due after 2015 to a ComEd financing trust.

(b)

(c)

As of December 31, 2009, ComEd’s liability for uncertain tax positions and related net interest payable were $251 million and $28 million, respectively. ComEd was unable to reasonably estimate the timing of liability and interest payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

(d)

In 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation. Under the terms of the agreements, ComEd will pay the City of 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.

(e)	Other purchase commitments include commitments for services, materials and information technology.

ComEd’s commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2010		2011- 2012		2013- 2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	80	$	80	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(b)		3		—		3		—		—
2007 City of Chicago Settlement ^(c)		6		3		3		—		—
Midwest Generation Capacity Reservation Agreement guarantee ^(d)		10		4		6		—		—
Surety bonds ^(e)		2		2		—		—		—
Rate relief commitments—settlement legislation ^(f)		1		1		—		—		—
Construction commitments ^(g)		91		16		23		52		—

Total commitments	$	193	$	106	$	35	$	52	$	—

(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)

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 $191 million is reflected in long-term debt in ComEd’s Consolidated Balance Sheet.

(c)	2007 City of Chicago Settlement—In December 2007, ComEd entered into an agreement with the City of Chicago. Under the terms of the agreement, ComEd will pay $55 million over six years, of which $8 million, $18 million and $23 million was paid in December 2009, 2008 and 2007, respectively.

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(d)

(e)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(f)	See Notes 2 and 18 of the Combined Notes to Consolidated Financial Statements for additional detail on ComEd’s rate relief commitments.

(g)	See Note 18 of the Combined Notes to Consolidated Financial Statements for additional detail on ComEd’s construction commitments.

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 2015 and beyond		All Other
	Total		2010		2011- 2012		2013- 2014		Due 2015 and beyond		All Other
Long-term debt ^(a)	$	2,824	$	415	$	625	$	550	$	1,234	$	—
Interest payments on long-term debt ^(b)		1,549		154		243		176		976		—
Liability and interest for uncertain tax positions ^(c)		1		—		—		—		—		1
Operating leases		73		15		30		27		1		—
Fuel purchase agreements ^(d)		574		152		173		123		126		—
Electric supply procurement		938		—		888		50		—		—
AEC purchase commitments		37		9		19		9		—		—
Other purchase obligations ^(e)		233		149		52		32		—		—

Total contractual obligations	$	6,229	$	894	$	2,030	$	967	$	2,337	$	1

(a)	Includes $415 million and $184 million due in 2010, and thereafter, respectively, to PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2009 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Includes estimated interest payments due to PECO financing trusts.

(c)	As of December 31, 2009, PECO’s liability for uncertain tax positions was $1 million. PECO was unable to reasonably estimate the timing of certain liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

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

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

PECO’s commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2010		2011- 2012		2013- 2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	39	$	32	$	7	$	—	$	—
Surety bonds ^(b)		3		3		—		—		—
Construction commitments ^(c)		105		35		45		25		—

Total commitments	$	147	$	70	$	52	$	25	$	—

(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.

(c)	See Note 18 of the Combined Notes to Consolidated Financial Statements for additional detail on PECO’s construction commitments.

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For additional information regarding:

•

commercial paper, see Note 9 of the Combined Notes to Consolidated Financial Statements.

•

long-term debt, see Note 9 of the Combined Notes to Consolidated Financial Statements.

•

liabilities related to uncertain tax positions, see Note 10 of the Combined Notes to Consolidated Financial Statements.

•

capital lease obligations, see Note 9 of the Combined Notes to Consolidated Financial Statements.

•

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

•

the nuclear decommissioning and SNF obligations, see Notes 11 and 12 of the Combined Notes to Consolidated Financial Statements.

•

regulatory commitments, see Note 2 of the Combined Notes to Consolidated Financial Statements.

Variable Interest Entities

Generation. Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation’s membership in NEIL are not consolidated in Exelon’s and Generation’s financial statements pursuant to the provisions of the authoritative guidance for VIEs. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information.

Financing Trusts of ComEd and PECO. The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, namely PECO Trust III, PECO Trust IV and PETT, are not consolidated in Exelon’s, ComEd’s and PECO’s financial statements. Amounts of $206 million and $599 million, respectively, owed by ComEd and PECO to these financing trusts were recorded as long-term debt to financing trusts and PETT within the Consolidated Balance Sheets as of December 31, 2009. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information.

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 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 additional discussion of nuclear insurance. For its types of insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s results of operations, cash flows or financial positions.

PECO Accounts Receivable Agreement

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a sale as of December 31, 2009. Under authoritative guidance effective January 1, 2010, this agreement will be accounted for as a secured borrowing. See Note 1 of the Combined Notes to Consolidated Financial Statements for additional information. PECO retains the servicing responsibility for the sold receivables and has recorded a servicing liability. The agreement terminates on September 16, 2010 unless extended in accordance with its terms. As of December 31, 2009, PECO was in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and will seek alternate financing. See Note 7 of the Combined Notes to Consolidated Financial Statements for additional information regarding the servicing liability.

New Accounting Pronouncements

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

In November 2008, the SEC issued a roadmap for the potential use of IFRS in the U.S. IFRS is a set of accounting standards developed by the International Accounting Standards Board, whose mission is to develop a single set of global financial reporting standards for general purpose financial statements. The roadmap indicates that the SEC will reconvene in 2011 to evaluate progress towards certain identified milestones and decide whether a mandatory IFRS conversion should be required for all U.S. issuers beginning with large accelerated filers in 2014. Further guidance from the SEC is expected in 2010. Exelon is currently evaluating the potential impact IFRS may have on its financial statements.

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Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

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 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, ComEd and PECO)

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 conditions, governmental regulatory and environmental policies, and other factors. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electricity, fossil fuel, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. PECO has transferred substantially all of its near term electricity commodity price risk to Generation through a PPA that expires at the end of 2010. PECO’s commodity price risk following the expiration of its generation rate caps and the PPA is addressed by its DSP Program, which allows for full cost recovery. As a mechanism to reduce commodity price risk relating to natural gas, PECO has implemented a natural gas procurement policy that is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s actual costs of natural gas are recovered from customers through the PAPUC’s PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. ComEd has transferred most of its near term commodity price risk to generating companies through the ICC approved procurement processes and a significant portion of its longer term commodity price risk to Generation through the five-year financial swap contract that expires on May 31, 2013. The Illinois Settlement Legislation provides for the pass-through of procurement costs by ComEd to its customers.

Generation

Generation’s energy contracts are accounted for under derivative accounting guidance. Economic hedges may qualify for the normal purchases and normal sales exception, which is discussed in Critical Accounting Policies and Estimates. Economic hedges 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 derivatives recorded at fair value are recognized in results of operations unless specific hedge accounting criteria are met and the derivatives are designated as cash flow hedges, in which case, changes in fair value are recorded in OCI and gains and losses are recognized in results of operations when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet the hedge criteria or are not designated as such are recognized in current results of operations.

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 financial derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2010 through 2012 and the ComEd financial swap contract during 2010 through 2013.

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The economic hedge activity resulted in a net mark-to-market energy contract asset position, excluding the rights of offset for derivative instruments subject to master netting agreements and the application of collateral, of $2,691 million at December 31, 2009, comprised of a net energy contract asset for cash flow hedges of $1,912 million and a net energy contract asset for other derivatives of $779 million. The net mark-to-market asset position for the portfolio at December 31, 2009 is a result of forward market prices decreasing relative to the contracted price of the derivative instruments, the majority of which are hedges of future power sales. Activity associated with the cash flow hedges is recognized through accumulated OCI until the period in which the associated physical sale of power occurs. At that time, the cash flow hedge’s mark-to-market position is reversed and reclassified as results of operations, which when combined with the impacts of the actual physical power sale, results in the ultimate recognition of net revenues at the contracted price.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over the three years leading to the spot market. As of December 31, 2009, the percentage of expected generation hedged was 91%-94%, 69%-72%, and 37%-40% for 2010, 2011, and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.

A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. 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 $5 reduction in the annual average Ni-Hub and PJM-West around-the-clock energy price based on December 31, 2009 market conditions and hedged position would be a decrease in pre-tax net income of approximately $40 million, $285 million and $497 million, respectively, for 2010, 2011, and 2012. Power price sensitivities are derived by adjusting the power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price exposure for its unhedged position. 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. The proprietary trading activities included volumes of 7,578 GWh, 8,891 GWh, and 20,323 GWh for the years ended December 31, 2009, 2008, and 2007, respectively. Trading portfolio activity for the year ended December 31, 2009 resulted in pre-tax gains of $1 million due to net mark-to-market losses of $83 million and realized gains of $84 million. Generation uses a 95% confidence interval, one day holding period and 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 the year ended December 31, 2009 of $6,771 million, Generation has not segregated proprietary trading activity in the

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following tables. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and VaR 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.

ComEd

The financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby ensuring that ComEd will be entitled to receive full cost recovery in rates. The change in fair value each period is recorded by ComEd with an offset to a regulatory asset or liability.

The contracts that ComEd has entered into as part of the initial ComEd auction and the RFP contracts are deemed to be derivatives that qualify for the normal purchases and normal sales exception under derivative accounting guidance. ComEd does not enter into derivatives for speculative or trading purposes. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivatives.

PECO

Generation and PECO have entered into a long-term full-requirements PPA under which PECO obtains all of its electric supply from Generation through 2010. The PPA is not considered a derivative. Pursuant to the PECO’s PAPUC-approved DSP Program, PECO began to procure electric supply in 2009 for the post-transition period beginning on January 1, 2011. PECO has entered into block contracts and full requirements fixed price contracts to procure electric supply for its residential, small commercial and medium commercial procurement classes. The full requirements fixed price contracts qualify for the normal purchases and normal sales scope exception. PECO records the fair value of the block contracts on its Consolidated Balance Sheets. However, since these block contracts were executed in accordance with the PAPUC-approved DSP Program and PECO will receive full cost recovery in rates, PECO did not elect hedge accounting and the fair value of the contracts is recorded by PECO as a regulatory asset or liability. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivatives.

PECO has also entered into derivative natural gas contracts to hedge its long-term price risk in the natural gas market. All of PECO’s natural gas supply and management agreements that are derivatives qualify for the normal purchases and normal sales exception.

Trading and Non-Trading Marketing Activities. The following detailed presentation of Exelon’s, Generation’s, ComEd’s and PECO’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s and PECO’s mark-to-market net asset or liability balance sheet position from January 1, 2008 to December 31, 2009. 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. This table excludes all normal purchases and normal sales contracts.


	Generation			ComEd			PECO			Intercompany Eliminations ^(e)			Exelon
Total mark-to-market energy contract net assets
(liabilities) at January 1, 2008^(a)^(g)	$	(564	)	$	456		$	—		$	—		$	(108	)
Total change in fair value during 2008 of contracts recorded in result of operations		602			—			—			—			602
Reclassification to realized at settlement of contracts recorded in results of operations		(131	)		—			—			—			(131	)
Ineffective portion recognized in income		44			—			—			—			44
Reclassification to realized at settlement from accumulated OCI ^(b)		544			—			—			(24	)		520
Effective portion of changes in fair value—recorded in OCI ^(c)(f)		1,784			—			—			(888	)		896
Changes in fair value—energy derivatives ^(d)		—			(912	)					912			—
Changes in collateral		(1,024	)		—			—			—			(1,024	)
Changes in net option premium paid/(received) ^(g)		124			—			—			—			124
Other income statement reclassifications ^(h)		(5	)		—			—			—			(5	)
Other balance sheet reclassifications		(11	)		—			—			—			(11	)

Total mark-to-market energy contract net assets
(liabilities) at December 31, 2008 ^(a)^(g)	$	1,363		$	(456	)	$	—		$	—		$	907
Total change in fair value during 2009 of contracts recorded in result of operations		137			—			—			—			137
Reclassification to realized at settlement of contracts recorded in results of operations		(24	)		—			—			—			(24	)
Ineffective portion recognized in income		(15	)		—			—			—			(15	)
Reclassification to realized at settlement from accumulated OCI^(b)		(1,559	)		—			—			267			(1,292	)
Effective portion of changes in fair value—recorded in OCI ^(c)(f)		2,052			—			—			(784	)		1,268
Changes in fair value—energy derivatives ^(d)		—			(515	)		(4	)		517			(2	)
Changes in collateral		(194	)		—			—			—			(194	)
Changes in net option premium paid/(received)^(g)		40			—			—			—			40
Other income statement reclassifications ^(h)		(46	)		—			—			—			(46	)
Other balance sheet reclassifications		15			—			—			—			15

Total mark-to-market energy contract net assets (liabilities) at December 31, 2009 ^(a)	$	1,769		$	(971	)	$	(4	)	$	—		$	794

(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)	For Generation, includes $267 million loss and $24 million gain of reclassifications from accumulated OCI to net income related to the settlement of the five-year financial swap contract with ComEd for the years ended December 31, 2009 and 2008, respectively.

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(c)

For Generation, includes $782 million and $888 million gain of changes in fair value of the five-year financial swap with ComEd for the years ended December 31, 2009 and 2008, respectively, and $2 million gain of changes in fair value of the block contracts with PECO for the year ended December 31, 2009.

(d)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2009 and December 31, 2008, ComEd recorded a regulatory asset of $971 million and $456 million, respectively, related to the mark-to-market derivative liability on the financial swap with Generation. During 2009 and 2008 this includes $782 million and $888 million of changes in fair value, respectively, and $267 million of gains and $24 million of losses, respectively, of reclassifications from regulatory asset to purchased power expense due to settlements. For PECO, the changes in fair value are recorded in a regulatory asset or liability. As of December 31, 2009, PECO recorded a $4 million regulatory asset related to the fair value of its mark-to-market derivative liability for its block contracts, which includes $2 million related to PECO’s block contracts with Generation.

(e)	Amounts related to the five-year financial swap between Generation and ComEd are eliminated in consolidation. Amounts related to the block contracts between Generation and PECO are also eliminated in consolidation.

(f)	For Generation, includes $15 million and $44 million of changes in cash flow hedge ineffectiveness, of which none was related to Generation’s financial swap contract with ComEd for the years ended December 31, 2009 and December 31, 2008, respectively.

(g)	Exelon and Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts. Refer to Note 8 of the Combined Notes to the Consolidated Financial Statements for further discussion.

(h)	Includes $46 million and $5 million of amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of the underlying transactions for the years ended December 31, 2009 and 2008, respectively.

The following tables detail the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2009 and 2008:


	December 31, 2009
	Generation^(a)(b)			ComEd^(a)			PECO^(a)			Intercompany Eliminations^(c)			Exelon
Current assets	$	678		$	—		$	—		$	(302	)	$	376
Noncurrent assets		1,310			—			—			(671	)		639

Total mark-to-market energy contract assets		1,988			—			—			(973	)		1,015

Current liabilities		(198	)		(302	)		—			302			(198	)
Noncurrent liabilities		(21	)		(669	)		(4	)		671			(23	)

Total mark-to-market energy contract liabilities		(219	)		(971	)		(4	)		973			(221	)

Total mark-to-market energy contract net assets (liabilities)	$	1,769		$	(971	)	$	(4	)	$	—		$	794

(a)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $302 million and $669 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract. Includes a noncurrent asset for Generation and a noncurrent liability for PECO of $2 million related to the fair value of PECO’s block contracts with Generation.

(b)

Current and noncurrent assets are shown net of collateral of $502 million and $376 million, respectively, and current liabilities are shown net of collateral of $69 million. The allocation of collateral had no impact to noncurrent liabilities. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $947 million at December 31, 2009.

(c)	Amounts related to the five-year financial swap between Generation and ComEd and the block contracts between Generation and PECO are eliminated in consolidation.

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	December 31, 2008
	Generation ^(a)(b)(d)			ComEd ^(a)			Intercompany Elimination ^(c)			Exelon ^(d)
Current assets	$	591		$	—		$	(111	)	$	480
Noncurrent assets		1,007			—			(345	)		662

Total mark-to-market energy contract assets		1,598			—			(456	)		1,142

Current liabilities		(212	)		(111	)		111			(212	)
Noncurrent liabilities		(23	)		(345	)		345			(23	)

Total mark-to-market energy contract liabilities		(235	)		(456	)		456			(235	)

Total mark-to-market energy contract net assets (liabilities)	$	1,363		$	(456	)	$	—		$	907

(a)	Includes current and noncurrent asset for Generation and current and noncurrent liability for ComEd of $111 million and $345 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract.

(b)

Current and noncurrent assets are shown net of collateral of $355 million and $333 million, respectively, and current liabilities are shown net of collateral of $65 million. The allocation of collateral had no impact to noncurrent liabilities. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $753 million at December 31, 2008.

(c)	Amounts related to the five-year financial swap between Generation and ComEd are eliminated in consolidation.

(d)

Exelon and Generation reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with current year presentation. Refer to Note 8 of the Combined Notes to the Consolidated Financial Statements for further discussion.

Fair Values

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 contracts, which are primarily option contracts, represents contracts for which external valuations are not available. These contracts are valued using the Black model, an industry standard option valuation model.

The fair values reflect the level of forward prices and volatility factors as of December 31, 2009 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, ComEd and PECO hold and sell. 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 the swap between Generation and ComEd, energy marketing, trading activities and such variations could be material. Refer to Note 8 of the Combined Notes to Consolidated Financial Statements for further information regarding valuation.

The following tables, which present maturity and source of fair value of mark-to-market energy contract net assets (liabilities), provides two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market asset or (liability). Second, the tables provide the maturity, by year, of the Registrants’ net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and either generate or require cash.

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Exelon


	Maturities Within																Total Fair Value
	2010			2011			2012			2013			2014		2015 and Beyond		Total Fair Value
Normal Operations, qualifying cash flow hedge contracts ^(a)(c):
Prices provided by external sources	$	379		$	225		$	59		$	4		$	1	$	—	$	668
Prices based on model or other valuation methods		—			(2	)		(1	)		(5	)		—		—		(8	)

Total	$	379		$	223		$	58		$	(1	)	$	1	$	—	$	660

Normal Operations, other derivative contracts ^(b)(c):
Actively quoted prices	$	(4	)	$	—		$	—		$	—		$	—	$	—	$	(4	)
Prices provided by external sources		(172	)		272			74			—			—		—		174
Prices based on model or other valuation methods		(25	)		(4	)		(7	)		—			—		—		(36	)

Total	$	(201	)	$	268		$	67		$	—		$	—	$	—	$	134

(a)	Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI.

(b)	Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash flow hedges are recorded in results of operations.

(c)	Amounts are shown net of collateral paid to and received from counterparties and offset against mark-to-market assets and liabilities of $947 million at December 31, 2009.

Generation


	Maturities Within															Total Fair Value
	2010			2011			2012			2013		2014		2015 and Beyond		Total Fair Value
Normal Operations, qualifying cash flow hedge contracts^(a)(c):
Prices provided by external sources	$	379		$	225		$	59		$	4	$	1	$	—	$	668
Prices based on model or other valuation methods		302			313			271			81		—		—		967

Total	$	681		$	538		$	330		$	85	$	1	$	—	$	1,635

Normal Operations, other derivative contracts ^(b)(c) :
Actively quoted prices	$	(4	)	$	—		$	—		$	—	$	—	$	—	$	(4	)
Prices provided by external sources		(172	)		272			74			—		—		—		174
Prices based on model or other valuation methods		(25	)		(4	)		(7	)		—		—		—		(36	)

Total	$	(201	)	$	268		$	67		$	—	$	—	$	—	$	134

(a)	Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI. Includes $971 million gain associated with the five-year financial swap with ComEd and $2 million related to the fair value of the PECO block contracts.

(b)	Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash flow hedges are recorded in results of operations.

(c)	Amounts are shown net of collateral paid to and received from counterparties and offset against mark-to-market assets and liabilities of $947 million at December 31, 2009.

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ComEd


	Maturities Within
	2010		2011		2012		2013		2014		2015 and Beyond		Total Fair Value
Prices based on model or other valuation methods ^(a)	$	302	$	311	$	272	$	86	$	—	$	—	$	971

(a)	Represents ComEd’s net liabilities associated with the five-year financial swap with Generation.

PECO


	Maturities Within
	2010		2011		2012		2013		2014		2015 and Beyond		Total Fair Value
Prices based on model or other valuation methods ^(a)	$	—	$	4	$	—	$	—	$	—	$	—	$	4

(a)	Represents PECO’s net liabilities associated with its block contracts executed under its DSP Program. Includes $2 million related to the fair value of PECO’s block contracts with Generation.

Cash Flow Hedges

The table below provides details of effective cash flow hedges included in the balance sheet as of December 31, 2009. The data in the table gives an indication of the magnitude of the hedges Generation has in place; however, since 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 rollforward of accumulated OCI related to cash flow hedges from January 1, 2008 to December 31, 2009, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges).


		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
	Income Statement Location	Energy Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative loss at January 1, 2008		$	(548)	^(a)	$	(292	)
Effective portion of changes in fair value			1,101	^(b)		567
Reclassifications from accumulated OCI to net income	Operating Revenue		328	^(c)		314
Ineffective portion recognized in income	Purchased Power		(26)			(26	)
Accumulated OCI derivative gain at December 31, 2008		$	855	^(a)	$	563
Effective portion of changes in fair value			1,227	^(b)		757
Reclassifications from accumulated OCI to net income	Operating Revenue		(939)	^(c)		(778	)
Ineffective portion recognized in income	Purchased Power		9			9

Accumulated OCI derivative gain at December 31, 2009		$	1,152	^(a),(d)	$	551

(a)

Includes $585 million gain, $275 million gain and $275 million loss, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2009, 2008, and 2007, respectively, and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO for the year ended December 31, 2009.

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(b)

Includes $471 million and $535 million gains, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2009 and 2008, respectively, and $1 million of gain, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the year ended December 31, 2009.

(c)	Includes $161 million loss and $15 million gain, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2009 and 2008, respectively.

(d)	Excludes $5 million gain, net of taxes, related to interest rate swaps settled for the year ended December 31, 2009. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information.

Credit Risk (Exelon, Generation, ComEd and PECO)

Generation

In September 2006, Generation participated in and won portions of the ComEd and Ameren electricity supply auctions. Beginning in 2007 and as a result of the auctions, Generation’s sales to counterparties other than ComEd and PECO increased due to the expiration of the PPA with ComEd on December 31, 2006. Illinois Settlement Legislation passed during 2007 established a new procurement process in place of the procurement auctions. Generation participated in the 2008 ComEd RFP procurement process and will continue to have credit risk in connection with contracts for sale of electricity resulting from the ICC-approved competitive procurement process. 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 has changed based on the credit worthiness of the new and existing counterparties, including ComEd and Ameren. For additional information on the Illinois auction and the various regulatory proceedings, see Note 2 of the Combined Notes to Consolidated Financial Statements.

Generation enters 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 enabling agreement, the credit department establishes margining thresholds and collateral requirements for each counterparty, which are defined in each contract. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. See the Collateral section below for additional information.

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The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2009. 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 credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs and NYMEX and ICE commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $123 million and $174 million, respectively. See Note 21 of the Combined Notes to Consolidated Financial Statements for further information.


Rating as of December 31, 2009	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	$	1,183	$	464	$	719	1	$	76
Non-investment grade		15		5		10	—		—
No external ratings
Internally rated—investment grade		34		5		29	—		—
Internally rated—non-investment grade		1		1		—	—		—

Total	$	1,233	$	475	$	758	1	$	76


	Maturity of Credit Risk Exposure
Rating as of December 31, 2009	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	1,071	$	112	$	—	$	1,183
Non-investment grade		15		—		—		15
No external ratings
Internally rated—investment grade		22		12		—		34
Internally rated—non-investment grade		1		—		—		1

Total	$	1,109	$	124	$	—	$	1,233


Net Credit Exposure by Type of Counterparty	As of December 31, 2009
Financial institutions	$	259
Investor-owned utilities, marketers and power producers		431
Other		68

Total	$	758

ComEd

Credit risk for ComEd is managed by credit and collection policies, which are consistent with state regulatory requirements. ComEd is currently obligated to provide service to all electric customers within its franchised territory. ComEd records a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. ComEd will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. In February 2010, the ICC approved ComEd’s tariffs to adjust rates annually

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through a rider mechanism to reflect increases or decreases in annual uncollectible accounts expense. The Illinois Settlement Legislation prohibits utilities, including ComEd, from terminating electric service to a residential electric space heat customer due to nonpayment between December 1 of any year through March 1 of the following year. ComEd’s ability to disconnect non space-heating residential customers is also impacted by certain weather restrictions, at any time of year, under the Illinois Public Utilities Act. ComEd will monitor the impact of its disconnection practices and will make any necessary adjustments to the provision for uncollectible accounts. ComEd did not have any customers representing over 10% of its revenues as of December 31, 2009. See Note 2 of the Combined Notes to the Consolidated Financial Statements for additional information regarding ComEd’s recently approved tariffs to adjust rates annually through a rider mechanism to reflect increases or decreases in annual uncollectible accounts expense.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on the price of energy in the spot market compared to the benchmark prices. The benchmark prices are the future prices of energy projected through the contract term and are set at the point of contract execution. If the price of energy in the spot market exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s credit exposure. As of December 31, 2009, ComEd’s credit exposure to energy suppliers was immaterial and did not exceed the unsecured levels allowed by contract.

PECO

Credit risk for PECO is managed by credit and collection policies, which are consistent with state regulatory requirements. PECO is currently obligated to provide service to all retail electric customers within its franchised territory. PECO records a provision for uncollectible accounts, primarily based upon historical experience, to provide for the potential loss from nonpayment by these customers. In accordance with PAPUC regulations, after November 30 and before April 1, an electric distribution utility or natural gas distribution utility shall not terminate service to customers with household incomes at or below 250% of the Federal poverty level. PECO’s provision for uncollectible accounts will continue to be affected by changes in prices as well as changes in PAPUC regulations. PECO did not have any customers representing over 10% of its revenues as of December 31, 2009.

PECO has a PPA with Generation under which Generation has agreed to supply PECO with 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 at prices that are currently below current market prices. The price for this electricity is essentially equal to the energy revenues earned from customers as specified by PECO’s 1998 restructuring settlement mandated by the Competition Act. As noted under Item 1A. Risk Factors, PECO could be negatively affected if Generation could not perform under the PPA.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from S&P, Fitch or Moody’s and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. If the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2009, PECO’s credit exposure to suppliers under its electric procurement contracts was

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immaterial and did not exceed unsecured levels allowed by the supplier master agreements. As of December 31, 2009, PECO had no net credit exposure to energy suppliers.

PECO does not obtain collateral from suppliers under its natural gas supply and management agreements. As of December 31, 2009, PECO had credit exposure of $13 million under its natural gas supply and management contracts.

Collateral (Generation, ComEd and PECO)

Generation

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the purchase and sale of electricity, fossil fuel and other commodities. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is 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. 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. In order to post collateral, Exelon depends on access to bank credit lines which serve as liquidity sources to fund collateral requirements. Since the banking industry issues started to surface in mid-2007, credit markets have tightened. Exelon will be required to renew most of its credit facilities in the 2011-2012 timeframe. The cost and availability to renew may be substantially different than when Exelon originally negotiated the existing liquidity facilities.

As of December 31, 2009, Generation was holding $965 million of cash collateral deposits received from counterparties and Generation had sent $12 million of cash collateral to counterparties. Net cash collateral deposits received of $947 million were offset against mark-to-market assets and liabilities. As of December 31, 2009, $6 million of cash collateral received was not offset against net mark-to-market assets and liabilities. As of December 31, 2008, Generation was holding $758 million of cash collateral deposits received from counterparties, of which $753 million was offset against mark-to-market assets and liabilities. As of December 31, 2008, $5 million of cash collateral received was not offset against net mark-to-market assets and liabilities. See Note 18 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

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ComEd

Beginning in 2007, under the Illinois auction rules and the SFCs that Generation and other suppliers entered into with ComEd, collateral postings will be one-sided from Generation and the other suppliers only. Therefore, if market prices fall below ComEd’s benchmark price levels, ComEd is not required to post collateral; however, if market prices rise above the benchmark price levels with ComEd, Generation and the other suppliers may be required to post collateral once certain unsecured credit limits are exceeded. Under the terms of the 5-year financial swap contract with ComEd, there are no immediate collateral provisions on either party. However, the swap contract also provides that: (1) if ComEd is downgraded below investment grade by Moody’s or S&P, or (2) if Generation is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by the applicable party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. As of December 31, 2009, there was no cash collateral or letters of credit posted between any suppliers, including Generation, and ComEd associated with the SFCs.

Illinois Settlement Legislation passed during 2007 established a new procurement process in place of the procurement auctions. Beginning in June 2009, under the terms of ComEd’s standard block energy contracts, collateral postings are only required from the supplier, including Generation, should exposures between market prices and benchmark prices exceed unsecured credit limits outlined in the agreement. The terms of ComEd’s procurement contracts provide that collateral requirements of the suppliers are affected by their security ratings. As stipulated in the Illinois Settlement Legislation as well as the ICC-approved procurement tariff, ComEd is permitted to recover its costs of procuring power and energy plus any prudent costs that a utility incurs in arranging and providing for the supply of electric power and energy. Thus all costs associated with collateral postings are recoverable from retail customers through ComEd’s procurement tariff. See Note 8 of the Combined Notes to Consolidated Financial Statements for further information.

PECO

If PECO lost its investment grade credit rating as of December 31, 2009, it would have been required to provide collateral of $5 million pursuant to PJM’s credit policy.

PECO’s supplier master agreements that govern the terms of its DSP program contracts do not contain provisions that would require PECO to post collateral.

PECO’s natural gas procurement contracts contain provisions that require PECO to post collateral. This collateral may be posted in the form of cash or credit support with threshold’s contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2009, PECO was not required to post any additional collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2009, PECO could have been required to provide collateral of approximately $49 million related to its natural gas procurement contracts, which is well within its current available credit facility capacity of $564 million.

RTOs and ISOs.

Generation, ComEd and PECO participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, New York ISO, MISO, Southwest Power Pool, Inc. and the ERCOT. 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

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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 the Registrants’ results of operations, cash flows and financial positions.

Exchange Traded Transactions.

Generation enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearinghouse acts as the counterparty to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX and ICE are significantly collateralized and have limited counterparty credit risk.

Generation and PECO

Fuel Procurement. Generation procures coal through annual, short-term and spot-market purchases and natural gas through annual, monthly and spot-market purchases. Nuclear fuel assemblies are obtained through long-term contracts for uranium concentrates and long-term contracts for conversion services, enrichment services and fuel fabrication services. The supply markets for coal, natural gas, uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 56% of Generation’s uranium concentrate requirements from 2010 through 2014 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial positions. See Note 18 of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.

PECO procures natural gas from suppliers under both short-term and long-term contracts. PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply agreements is mitigated by its ability to recover its natural gas costs through the PAPUC PGC that allows PECO to adjust rates quarterly to reflect realized natural gas prices.

Exelon

Exelon’s consolidated balance sheets, as of December 31, 2009, included a $602 million net investment in direct financing leases. The investment in direct financing leases represents the estimated residual value of leased assets at the end of the respective lease terms of $1.5 billion, less unearned income of $890 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to require the lessees to return the leasehold interests or to arrange a service contract with a third party for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. Lessee performance under the lease agreements is supported by collateral and credit enhancement measures including letters of credit, surety bonds and credit swaps. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these direct financing leases. During 2008 and 2009, the entity providing the credit enhancement for one of the lessees did not meet the credit rating requirements of the lease. Consequently, Exelon has indefinitely extended a waiver and reduction of the rating requirement, which Exelon may terminate by giving 90 days notice to the lessee.

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Interest-Rate Risk (Exelon, Generation and ComEd)

The Registrants use a combination of fixed-rate and variable-rate debt to manage 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, 2009, Exelon had $100 million of notional amounts of fair value hedges outstanding. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in Exelon’s, Generation’s and ComEd’s pre-tax earnings for the year ended December 31, 2009. This calculation holds all other variables constant and assumes only the discussed changes in interest rates.

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, 2009, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $412 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of equity price risk as a result of the current capital and credit market conditions.

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ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Generation

General

Generation operates in a single business segment and its operations consist of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.

Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION—Executive Overview” of this Form 10-K.

Results of Operations

Year Ended December 31, 2009 Compared To Year Ended December 31, 2008 and Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

A discussion of Generation’s results of operations for 2009 compared to 2008 and 2008 compared to 2007 is set forth under “Results of Operations—Generation” in “EXELON CORPORATION—Results of Operations” of this Form 10-K.

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 long-term debt, 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 revolving credit facilities of $4.8 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.

See the “EXELON CORPORATION—Liquidity and Capital Resources” and Note 9 of the Combined Notes to the Financial Statements of this Form 10-K 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 Form 10-K.

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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 Form 10-K.

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 Form 10-K.

Credit Matters

A discussion of credit matters pertinent to Generation is set forth under “Credit Matters” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of Generation’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.

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

General

ComEd operates in a single business segment and its operations consist of the purchase and regulated retail and wholesale sale of electricity and distribution and transmission services in northern Illinois, including the City of Chicago.

Executive Overview

A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION—Executive Overview” of this Form 10-K.

Results of Operations

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 and Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

A discussion of ComEd’s results of operations for 2009 compared to 2008 and for 2008 compared to 2007 is set forth under “Results of Operations—ComEd” in “EXELON CORPORATION—Results of Operations” of this Form 10-K.

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 long-term debt, or credit facility borrowings. 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. At December 31, 2009, ComEd had access to a revolving credit facility with aggregate bank commitments of $952 million. See the “Credit Matters” section of “Liquidity and Capital Resources” for additional discussion.

See the “EXELON CORPORATION—Liquidity and Capital Resources” and Note 9 of the Combined Notes to the Financial Statements of this Form 10-K for further discussion.

Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, and contributions to Exelon’s pension plans. Additionally, ComEd operates 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.

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 Form 10-K.

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 Form 10-K.

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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 Form 10-K.

Credit Matters

A discussion of credit matters pertinent to ComEd is set forth under “Credit Matters” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of ComEd’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.

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.”

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ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

PECO

General

PECO operates in two business segments that are aggregated into one reportable segment, and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia.

Executive Overview

A discussion of items pertinent to PECO’s executive overview is set forth under “EXELON CORPORATION—Executive Overview” of this Form 10-K.

Results of Operations

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 and Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

A discussion of PECO’s results of operations for 2009 compared to 2008 and for 2008 compared to 2007 is set forth under “Results of Operations—PECO” in “EXELON CORPORATION—Results of Operations” of this Form 10-K.

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 long-term debt, commercial paper, or participation in the intercompany money pool. 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. At December 31, 2009, PECO had access to a revolving credit facility with aggregate bank commitments of $574 million. See the “Credit Matters” section of “Liquidity and Capital Resources” for additional 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. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

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 Form 10-K.

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 Form 10-K.

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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 Form 10-K.

Credit Matters

A discussion of credit matters pertinent to PECO is set forth under “Credit Matters” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of PECO’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under “Contractual Obligations and Off-Balance Sheet Arrangements” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.

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.”

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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, 2009. 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, 2009, Exelon’s internal control over financial reporting was effective.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 5, 2010

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Management’s Report on Internal Control Over Financial Reporting

The management of Exelon Generation Company (Generation) is responsible for establishing and maintaining adequate internal control over financial reporting. Generation’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.

Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2009. 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, Generation’s management concluded that, as of December 31, 2009, Generation’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

The management of Commonwealth Edison Company (ComEd) is responsible for establishing and maintaining adequate internal control over financial reporting. ComEd’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.

ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, 2009. 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, ComEd’s management concluded that, as of December 31, 2009, ComEd’s internal control over financial reporting was effective.

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Management’s Report on Internal Control Over Financial Reporting

The management of PECO Energy Company (PECO) is responsible for establishing and maintaining adequate internal control over financial reporting. PECO’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.

PECO’s management conducted an assessment of the effectiveness of PECO’s internal control over financial reporting as of December 31, 2009. 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, PECO’s management concluded that, as of December 31, 2009, PECO’s internal control over financial reporting was effective.

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Report of Independent Registered Public Accounting Firm

To The Shareholders and the Board of Directors of Exelon Corporation:

In our opinion, the consolidated financial statements listed in the accompanying 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index appearing under item 15(a)(1)(ii) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 to the consolidated financial statements, Exelon Corporation changed its method of accounting for nuclear decommissioning trust fund investments as of January 1, 2008.

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.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 5, 2010

156

Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated financial statements listed in the accompanying 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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 accompanying 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 to the consolidated financial statements, Generation changed its method of accounting for nuclear decommissioning trust fund investments as of January 1, 2008.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 5, 2010

157

Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated financial statements listed in the accompanying 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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 accompanying 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 5, 2010

158

Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated financial statements listed in the accompanying 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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 accompanying 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 5, 2010

159

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Operations


	For the Years Ended December 31,
(In millions, except per share data)	2009			2008			2007
Operating revenues	$	17,318		$	18,859		$	18,916
Operating expenses
Purchased power		3,215			4,270			5,282
Fuel		2,066			2,312			2,360
Operating and maintenance		4,612			4,538			4,289
Operating and maintenance for regulatory required programs		63			28			—
Depreciation and amortization		1,834			1,634			1,520
Taxes other than income		778			778			797

Total operating expenses		12,568			13,560			14,248

Operating income		4,750			5,299			4,668

Other income and deductions
Interest expense, net		(654	)		(699	)		(647	)
Interest expense to affiliates, net		(77	)		(133	)		(203	)
Equity in losses of unconsolidated affiliates and investments		(27	)		(26	)		(106	)
Other, net		426			(407	)		460

Total other income and deductions		(332	)		(1,265	)		(496	)

Income from continuing operations before income taxes		4,418			4,034			4,172
Income taxes		1,712			1,317			1,446

Income from continuing operations		2,706			2,717			2,726
Discontinued operations
Income (loss) from discontinued operations (net of taxes of $0, $1 and $3, respectively)		1			(1	)		6
Gain on disposal of discontinued operations (net of taxes of $0, $14 and $2, respectively)		—			21			4

Income from discontinued operations, net		1			20			10

Net income	$	2,707		$	2,737		$	2,736

Average shares of common stock outstanding:
Basic		659			658			670
Diluted		662			662			676
Earnings per average common share—basic:
Income from continuing operations	$	4.10		$	4.13		$	4.06
Income from discontinued operations		—			0.03			0.02

Net income	$	4.10		$	4.16		$	4.08

Earnings per average common share—diluted:
Income from continuing operations	$	4.09		$	4.10		$	4.03
Income from discontinued operations		—			0.03			0.02

Net income	$	4.09		$	4.13		$	4.05

Dividends per common share	$	2.10		$	2.03		$	1.76

See the Combined Notes to Consolidated Financial Statements

160

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Cash flows from operating activities
Net income	$	2,707		$	2,737		$	2,736
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		2,601			2,308			2,183
Impairment of long-lived assets		223			—			—
Deferred income taxes and amortization of investment tax credits		756			374			(104	)
Net fair value changes related to derivatives		(95	)		(515	)		102
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		(207	)		363			(70	)
Other non-cash operating activities		652			870			734
Changes in assets and liabilities:
Accounts receivable		234			67			(585	)
Inventories		51			(109	)		9
Accounts payable, accrued expenses and other current liabilities		(254	)		(44	)		146
Option premiums (paid) received, net		(40	)		(124	)		27
Counterparty collateral received (posted), net		196			1,027			(516	)
Income taxes		(29	)		(38	)		160
Pension and non-pension postretirement benefit contributions		(588	)		(230	)		(204	)
Other assets and liabilities		(113	)		(135	)		(122	)

Net cash flows provided by operating activities		6,094			6,551			4,496

Cash flows from investing activities
Capital expenditures		(3,273	)		(3,117	)		(2,674	)
Proceeds from nuclear decommissioning trust fund sales		22,905			17,202			7,312
Investment in nuclear decommissioning trust funds		(23,144	)		(17,487	)		(7,527	)
Proceeds from sales of investments		41			—			95
Purchases of investments		(28	)		—			—
Change in restricted cash		35			29			(45	)
Other investing activities		6			(5	)		(70	)

Net cash flows used in investing activities		(3,458	)		(3,378	)		(2,909	)

Cash flows from financing activities
Changes in short-term debt		(56	)		(405	)		311
Issuance of long-term debt		1,987			2,265			1,621
Retirement of long-term debt		(1,773	)		(1,398	)		(262	)
Retirement of long-term debt to financing affiliates		(709	)		(1,038	)		(1,020	)
Dividends paid on common stock		(1,385	)		(1,335	)		(1,180	)
Proceeds from employee stock plans		42			130			215
Purchase of treasury stock		—			(436	)		(1,208	)
Purchase of forward contract in relation to certain treasury stock		—			(64	)		(79	)
Other financing activities		(3	)		68			102

Net cash flows used in financing activities		(1,897	)		(2,213	)		(1,500	)

Increase in cash and cash equivalents		739			960			87
Cash and cash equivalents at beginning of period		1,271			311			224

Cash and cash equivalents at end of period	$	2,010		$	1,271		$	311

See the Combined Notes to Consolidated Financial Statements

161

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009		2008
ASSETS

Current assets
Cash and cash equivalents	$	2,010	$	1,271
Restricted cash and investments		40		75
Accounts receivable, net
Customer		1,563		1,928
Other		486		324
Mark-to-market derivative assets		376		480
Inventories, net
Fossil fuel		198		315
Materials and supplies		559		528
Other		209		209

Total current assets		5,441		5,130

Property, plant and equipment, net		27,341		25,813
Deferred debits and other assets
Regulatory assets		4,872		5,940
Nuclear decommissioning trust funds		6,669		5,500
Investments		704		670
Investments in affiliates		20		45
Goodwill		2,625		2,625
Mark-to-market derivative assets		649		679
Other		859		1,144

Total deferred debits and other assets		16,398		16,603

Total assets	$	49,180	$	47,546

See the Combined Notes to Consolidated Financial Statements

162

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009			2008
LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities
Short-term borrowings	$	155		$	211
Long-term debt due within one year		639			29
Long-term debt to PECO Energy Transition Trust due within one year		415			319
Accounts payable		1,345			1,416
Mark-to-market derivative liabilities		198			212
Accrued expenses		923			1,151
Deferred income taxes		152			77
Other		411			396

Total current liabilities		4,238			3,811

Long-term debt		10,995			11,397
Long-term debt to PECO Energy Transition Trust		—			805
Long-term debt to other financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,750			4,939
Asset retirement obligations		3,434			3,734
Pension obligations		3,625			4,111
Non-pension postretirement benefit obligations		2,180			2,255
Spent nuclear fuel obligation		1,017			1,015
Regulatory liabilities		3,492			2,520
Mark-to-market derivative liabilities		23			23
Other		1,309			1,412

Total deferred credits and other liabilities		20,830			20,009

Total liabilities		36,453			36,412

Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 660 and 658 shares outstanding at December 31, 2009 and December 31, 2008, respectively)		8,923			8,816
Treasury stock, at cost (35 and 35 shares held at December 31, 2009 and December 31, 2008, respectively)		(2,328	)		(2,338	)
Retained earnings		8,134			6,820
Accumulated other comprehensive loss, net		(2,089	)		(2,251	)

Total shareholders’ equity		12,640			11,047

Total liabilities and shareholders’ equity	$	49,180		$	47,546

See the Combined Notes to Consolidated Financial Statements

163

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity


(In millions, shares in thousands)	Issued Shares	Common Stock			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
Balance, December 31, 2006	682,474	$	8,314		$	(630	)	$	3,426		$	(1,103	)	$	10,007
Net income	—		—			—			2,736			—			2,736
Long-term incentive plan activity	6,455		328			—			—			—			328
Employee stock purchase plan issuances	254		16			—			—			—			16
Common stock purchases	—		(79	)		(1,208	)		—			—			(1,287	)
Common stock dividends	—		—			—			(1,219	)		—			(1,219	)
Adoption of accounting for uncertain tax positions	—		—			—			(13	)		—			(13	)
Other comprehensive loss, net of income taxes of $(290)	—		—			—			—			(431	)		(431	)

Balance, December 31, 2007	689,183	$	8,579		$	(1,838	)	$	4,930		$	(1,534	)	$	10,137
Net income	—		—			—			2,737			—			2,737
Long-term incentive plan activity	3,452		217			—			—			—			217
Employee stock purchase plan issuances	318		19			—			—			—			19
Common stock purchases	—		1			(500	)		—			—			(499	)
Common stock dividends	—		—			—			(1,007	)		—			(1,007	)
Adoption of the fair value option for financial assets and liabilities, net of income taxes of $286	—		—			—			160			(160	)		—
Other comprehensive loss, net of income taxes of $(354)	—		—			—			—			(557	)		(557	)

Balance, December 31, 2008	692,953	$	8,816		$	(2,338	)	$	6,820		$	(2,251	)	$	11,047
Net income	—		—			—			2,707			—			2,707
Long-term incentive plan activity	1,612		107			10			(5	)		—			112
Common stock dividends	—		—			—			(1,388	)		—			(1,388	)
Other comprehensive income, net of income taxes of $119	—		—			—			—			162			162

Balance, December 31, 2009	694,565	$	8,923		$	(2,328	)	$	8,134		$	(2,089	)	$	12,640

See the Combined Notes to Consolidated Financial Statements

164

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Comprehensive Income


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Net Income	$	2,707		$	2,737		$	2,736
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic cost, net of income taxes of $(6), $(6) and $(4), respectively		(13	)		(9	)		(9	)
Actuarial loss reclassified to periodic cost, net of income taxes of $74, $52 and $57, respectively		93			60			74
Transition obligation reclassified to periodic cost, net of income taxes of $2, $2 and $2, respectively		3			3			3
Pension and non-pension postretirement benefit plan valuation adjustment, net of income taxes of $47, $(959) and $1, respectively		86			(1,459	)		19
Change in unrealized gain (loss) on cash flow hedges, net of income taxes of $(2), $563 and $(345), respectively		(12	)		855			(513	)
Change in unrealized gain (loss) on marketable securities, net of income taxes of $3, $(6) and $(1), respectively		5			(7	)		(5	)

Other comprehensive (loss) income		162			(557	)		(431	)

Comprehensive income	$	2,869		$	2,180		$	2,305

See the Combined Notes to Consolidated Financial Statements

165

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Operations


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Operating revenues
Operating revenues	$	6,231		$	7,168		$	7,211
Operating revenues from affiliates		3,472			3,586			3,538

Total operating revenues		9,703			10,754			10,749

Operating expenses
Purchased power		1,338			1,867			2,705
Fuel		1,594			1,705			1,746
Operating and maintenance		2,632			2,432			2,190
Operating and maintenance from affiliates		306			285			264
Depreciation and amortization		333			274			267
Taxes other than income		205			197			185

Total operating expenses		6,408			6,760			7,357

Operating income		3,295			3,994			3,392

Other income and deductions
Interest expense		(113	)		(136	)		(161	)
Equity in earnings (losses) of investments		(3	)		(1	)		1
Other, net		376			(469	)		155

Total other income and deductions		260			(606	)		(5	)

Income from continuing operations before income taxes		3,555			3,388			3,387
Income taxes		1,433			1,130			1,362

Income from continuing operations		2,122			2,258			2,025
Discontinued operations
Gain on disposal of discontinued operations (net of taxes of $0, $15 and $2, respectively)		—			20			4

Income from discontinued operations, net		—			20			4

Net income	$	2,122		$	2,278		$	2,029

See the Combined Notes to Consolidated Financial Statements

166

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Cash flows from operating activities
Net income	$	2,122		$	2,278		$	2,029
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		1,098			947			928
Impairment of long-lived assets		223			—			—
Deferred income taxes and amortization of investment tax credits		671			327			(31	)
Net fair value changes related to derivatives		(95	)		(515	)		139
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		(207	)		363			(70	)
Other non-cash operating activities		104			332			256
Changes in assets and liabilities:
Accounts receivable		172			79			(204	)
Receivables from and payables to affiliates, net		(54	)		(51	)		288
Inventories		(29	)		(60	)		(38	)
Accounts payable, accrued expenses and other current liabilities		(43	)		(91	)		(22	)
Option premiums (paid) received, net		(40	)		(124	)		27
Counterparty collateral received (posted), net		195			1,029			(518	)
Income taxes		79			115			269
Pension and non-pension postretirement benefit contributions		(265	)		(103	)		(99	)
Other assets and liabilities		(1	)		(81	)		40

Net cash flows provided by operating activities		3,930			4,445			2,994

Cash flows from investing activities
Capital expenditures		(1,977	)		(1,699	)		(1,269	)
Proceeds from nuclear decommissioning trust fund sales		22,905			17,202			7,312
Investment in nuclear decommissioning trust funds		(23,144	)		(17,487	)		(7,527	)
Proceeds from sales of investments		—			—			95
Changes in Exelon intercompany money pool		—			—			13
Change in restricted cash		17			25			(45	)
Other investing activities		(21	)		(8	)		(3	)

Net cash flows used in investing activities		(2,220	)		(1,967	)		(1,424	)

Cash flows from financing activities
Issuance of long-term debt		1,546			—			746
Retirement of long-term debt		(1,065	)		(13	)		(11	)
Distribution to member		(2,276	)		(1,545	)		(2,357	)
Contribution from member		57			86			54
Other financing activities		(8	)		2			(3	)

Net cash flows used in financing activities		(1,746	)		(1,470	)		(1,571	)

Increase (decrease) in cash and cash equivalents		(36	)		1,008			(1	)
Cash and cash equivalents at beginning of period		1,135			127			128

Cash and cash equivalents at end of period	$	1,099		$	1,135		$	127

See the Combined Notes to Consolidated Financial Statements

167

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009		2008
ASSETS

Current assets
Cash and cash equivalents	$	1,099	$	1,135
Restricted cash and cash equivalents		5		22
Accounts receivable, net
Customer		495		673
Other		112		108
Mark-to-market derivative assets		376		480
Mark-to-market derivative assets with affiliate		302		111
Receivables from affiliates		297		277
Inventories, net
Fossil fuel		102		143
Materials and supplies		470		435
Other		102		102

Total current assets		3,360		3,486

Property, plant and equipment, net		9,809		8,907
Deferred debits and other assets
Nuclear decommissioning trust funds		6,669		5,500
Investments		46		33
Receivable from affiliate		1		1
Mark-to-market derivative assets		639		662
Mark-to-market derivative assets with affiliate		671		345
Prepaid pension asset		1,027		949
Other		184		201

Total deferred debits and other assets		9,237		7,691

Total assets	$	22,406	$	20,084

See the Combined Notes to Consolidated Financial Statements

168

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009		2008
LIABILITIES AND EQUITY
Current liabilities
Long-term debt due within one year	$	26	$	12
Accounts payable		826		792
Mark-to-market derivative liabilities		198		212
Accrued expenses		670		761
Payables to affiliates		80		78
Deferred income taxes		399		256
Other		63		57

Total current liabilities		2,262		2,168

Long-term debt		2,967		2,502
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,707		1,968
Asset retirement obligations		3,316		3,536
Pension obligations		—		63
Non-pension postretirement benefit obligations		659		576
Spent nuclear fuel obligation		1,017		1,015
Payables to affiliates		2,228		1,336
Mark-to-market derivative liabilities		21		23
Other		437		331

Total deferred credits and other liabilities		10,385		8,848

Total liabilities		15,614		13,518

Commitments and contingencies
Equity
Member’s equity
Membership interest		3,464		3,407
Undistributed earnings		2,169		2,323
Accumulated other comprehensive income, net		1,157		835

Total member’s equity		6,790		6,565
Noncontrolling interest		2		1

Total equity		6,792		6,566

Total liabilities and equity	$	22,406	$	20,084

See the Combined Notes to Consolidated Financial Statements

169

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Changes in Member’s Equity


	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interest		Total Equity
Balance, December 31, 2006	$	3,267	$	1,800		$	416		$	1	$	5,484
Net Income		—		2,029			—			—		2,029
Distribution to member		—		(2,357	)		—			—		(2,357	)
Allocation of tax benefit from member		54		—			—			—		54
Adoption of accounting for uncertain tax positions		—		(43	)		—			—		(43	)
Other comprehensive loss, net of income taxes of $(524)		—		—			(797	)		—		(797	)

Balance, December 31, 2007	$	3,321	$	1,429		$	(381	)	$	1	$	4,370
Net Income		—		2,278			—			—		2,278
Distribution to member		—		(1,545	)		—			—		(1,545	)
Allocation of tax benefit from member		86		—			—			—		86
Adoption of the fair value option for financial assets and liabilities, net of taxes of $286		—		160			(160	)		—		—
Adjustment of the adoption of accounting for uncertain tax positions		—		1			—			—		1
Other comprehensive loss, net of income taxes of $908		—		—			1,376			—		1,376

Balance, December 31, 2008	$	3,407	$	2,323		$	835		$	1	$	6,566
Net income		—		2,122			—			—		2,122
Distribution to member		—		(2,276	)		—			—		(2,276	)
Allocation of tax benefit from member		57		—			—			—		57
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes of $17		—		—			20			—		20
Other comprehensive income, net of income taxes of $199		—		—			302			—		302
Noncontrolling interest in income of consolidated entity		—		—			—			1		1

Balance, December 31, 2009	$	3,464	$	2,169		$	1,157		$	2	$	6,792

See the Combined Notes to Consolidated Financial Statements

170

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Comprehensive Income


	For the Years Ended December 31,
(In millions)	2009		2008			2007
Net Income	$	2,122	$	2,278		$	2,029
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Pension and non-pension postretirement benefit plan valuation adjustment, net of income taxes of $0, $(18) and $3, respectively		—		(27	)		5
Change in unrealized gain (loss) on cash flow hedges, net of income taxes of $199, $926 and $(525), respectively		302		1,403			(795	)
Change in unrealized loss on marketable securities, net of income taxes of $0, $0 and $(2), respectively		—		—			(7	)

Other comprehensive (loss) income		302		1,376			(797	)

Comprehensive income	$	2,424	$	3,654		$	1,232

See the Combined Notes to Consolidated Financial Statements

171

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Operations


	For the Years Ended December 31,
(in millions)	2009			2008			2007
Operating revenues
Operating revenues	$	5,772		$	6,129		$	6,099
Operating revenues from affiliates		2			7			5

Total operating revenues		5,774			6,136			6,104

Operating expenses
Purchased power		1,609			2,077			2,270
Purchased power from affiliate		1,456			1,505			1,477
Operating and maintenance		863			929			895
Operating and maintenance from affiliate		165			168			196
Operating and maintenance for regulatory required programs		63			28			—
Depreciation and amortization		494			464			440
Taxes other than income		281			298			314

Total operating expenses		4,931			5,469			5,592

Operating income		843			667			512

Other income and deductions
Interest expense		(306	)		(327	)		(265	)
Interest expense to affiliates, net		(13	)		(21	)		(53	)
Equity in losses of unconsolidated affiliates		—			(8	)		(7	)
Other, net		79			18			58

Total other income and deductions		(240	)		(338	)		(267	)

Income before income taxes		603			329			245
Income taxes		229			128			80

Net income	$	374		$	201		$	165

See the Combined Notes to Consolidated Financial Statements

172

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Cash flows from operating activities
Net income	$	374		$	201		$	165
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		495			465			441
Deferred income taxes and amortization of investment tax credits		265			258			82
Other non-cash operating activities		309			264			206
Changes in assets and liabilities:
Accounts receivable		29			(133	)		(103	)
Inventories		4			(4	)		6
Accounts payable, accrued expenses and other current liabilities		(48	)		43			120
Receivables from and payables to affiliates, net		(27	)		112			(132	)
Income taxes		(105	)		(95	)		(93	)
Pension and non-pension postretirement benefit contributions		(214	)		(55	)		(53	)
Other assets and liabilities		(62	)		23			(119	)

Net cash flows provided by operating activities		1,020			1,079			520

Cash flows from investing activities
Capital expenditures		(854	)		(953	)		(1,040	)
Proceeds from sales of investments		41			—			—
Purchases of investments		(28	)		—			—
Other investing activities		20			(5	)		25

Net cash flows used in investing activities		(821	)		(958	)		(1,015	)

Cash flows from financing activities
Changes in short-term debt		95			(310	)		310
Issuance of long-term debt		191			1,324			705
Retirement of long-term debt		(208	)		(760	)		(147	)
Retirement of long-term debt to financing affiliates		—			(429	)		(349	)
Contributions from parent		8			14			28
Dividends paid on common stock		(240	)		—			—
Other financing activities		(1	)		—			—

Net cash flows (used in) provided by financing activities		(155	)		(161	)		547

Increase (decrease) in cash and cash equivalents		44			(40	)		52
Cash and cash equivalents at beginning of period		47			87			35

Cash and cash equivalents at end of period	$	91		$	47		$	87

See the Combined Notes to Consolidated Financial Statements

173

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009		2008
ASSETS

Current assets
Cash and cash equivalents	$	91	$	47
Restricted cash		2		1
Accounts receivable, net
Customer		676		798
Other		318		162
Inventories, net		71		75
Regulatory assets		358		169
Deferred income taxes		39		32
Other		24		25

Total current assets		1,579		1,309

Property, plant and equipment, net		12,125		11,655

Deferred debits and other assets
Regulatory assets		1,096		858
Investments		28		34
Goodwill		2,625		2,625
Receivable from affiliates		1,920		1,291
Prepaid pension asset		907		847
Other		417		618

Total deferred debits and other assets		6,993		6,273

Total assets	$	20,697	$	19,237

See the Combined Notes to Consolidated Financial Statements

174

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009		2008
LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities
Short-term borrowings	$	155	$	60
Long-term debt due within one year		213		17
Accounts payable		274		307
Accrued expenses		282		306
Payables to affiliates		177		179
Customer deposits		131		119
Mark-to-market derivative liability with affiliate		302		111
Other		63		54

Total current liabilities		1,597		1,153

Long-term debt		4,498		4,709
Long-term debt to financing trust		206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,648		2,369
Asset retirement obligations		95		174
Non-pension postretirement benefits obligations		241		203
Regulatory liabilities		3,145		2,440
Mark-to-market derivative liability with affiliate		669		345
Other		716		903

Total deferred credits and other liabilities		7,514		6,434

Total liabilities		13,815		12,502

Commitments and contingencies

Shareholders’ equity
Common stock		1,588		1,588
Other paid-in capital		4,990		4,982
Retained earnings		304		170
Accumulated other comprehensive loss, net		—		(5	)

Total shareholders’ equity		6,882		6,735

Total liabilities and shareholders’ equity	$	20,697	$	19,237

See the Combined Notes to Consolidated Financial Statements

175

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity


(In millions)	Common Stock		Other Paid-In Capital		Retained (Deficit) Earnings Unappropriated			Retained Earnings Appropriated			Accumulated Other Comprehensive (Loss) Income			Total Shareholders’ Equity
Balance, December 31, 2006	$	1,588	$	4,906	$	(1,632	)	$	1,439		$	(3	)	$	6,298
Net income		—		—		165			—			—			165
Allocation of tax benefit from parent		—		28		—			—			—			28
Appropriation of retained earnings for future dividends		—		—		(171	)		171			—			—
Adoption of accounting for uncertain tax positions		—		34		(1	)		—			—			33
Other comprehensive income, net of income taxes of $3		—		—		—			—			4			4

Balance, December 31, 2007	$	1,588	$	4,968	$	(1,639	)	$	1,610		$	1		$	6,528
Net income		—		—		201			—			—			201
Allocation of tax benefit from parent		—		14		—			—			—			14
Appropriation of retained earnings for future dividends		—		—		(199	)		199			—			—
Adjustment of the adoption of accounting for uncertain tax positions		—		—		(2	)		—			—			(2	)
Other comprehensive loss, net of income taxes of $(4)		—		—		—			—			(6	)		(6	)

Balance, December 31, 2008		1,588		4,982		(1,639	)		1,809			(5	)		6,735
Net income		—		—		374			—			—			374
Allocation of tax benefit from parent		—		8		—			—			—			8
Appropriation of retained earnings for future dividends		—		—		(374	)		374			—			—
Common stock dividends		—		—		—			(240	)		—			(240	)
Other comprehensive income, net of income taxes of $3		—		—		—			—			5			5

Balance, December 31, 2009	$	1,588	$	4,990	$	(1,639	)	$	1,943		$	—		$	6,882

See the Combined Notes to Consolidated Financial Statements

176

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income


	For the Years Ended December 31,
(In millions)	2009		2008			2007
Net Income	$	374	$	201		$	165
Other comprehensive income (loss)
Change in unrealized gain on cash flow hedges, net of income taxes of $0, $0 and $2, respectively		—		—			4
Change in unrealized gain (loss) on marketable securities, net of income taxes of $3, $(4) and $1, respectively		5		(6	)		—

Other comprehensive income (loss)		5		(6	)		4

Comprehensive income	$	379	$	195		$	169

See the Combined Notes to Consolidated Financial Statements

177

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Operations


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Operating revenues
Operating revenues	$	5,302		$	5,553		$	5,596
Operating revenues from affiliates		9			14			17

Total operating revenues		5,311			5,567			5,613

Operating expenses
Purchased power		269			328			307
Purchased power from affiliate		2,005			2,083			2,059
Fuel		472			607			617
Operating and maintenance		545			641			513
Operating and maintenance from affiliate		95			90			117
Depreciation and amortization		952			854			773
Taxes other than income		276			265			280

Total operating expenses		4,614			4,868			4,666

Operating income		697			699			947

Other income and deductions
Interest expense		(124	)		(112	)		(94	)
Interest expense to affiliates, net		(63	)		(114	)		(154	)
Equity in losses of unconsolidated affiliates		(24	)		(16	)		(7	)
Other, net		13			18			45

Total other income and deductions		(198	)		(224	)		(210	)

Income before income taxes		499			475			737
Income taxes		146			150			230

Net income		353			325			507
Preferred security dividends		4			4			4

Net income on common stock	$	349		$	321		$	503

See the Combined Notes to Consolidated Financial Statements

178

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Cash flows from operating activities
Net income	$	353		$	325		$	507
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		952			854			773
Deferred income taxes and amortization of investment tax credits		(210	)		(220	)		(186	)
Other non-cash operating activities		141			194			86
Changes in assets and liabilities:
Accounts receivable		36			(120	)		(158	)
Inventories		76			(45	)		40
Accounts payable, accrued expenses and other current liabilities		(123	)		46			78
Receivables from and payables to affiliates, net		45			(1	)		(58	)
Income taxes		(18	)		(12	)		(51	)
Pension and non-pension postretirement benefit contributions		(52	)		(38	)		(31	)
Other assets and liabilities		(34	)		(14	)		(20	)

Net cash flows provided by operating activities		1,166			969			980

Cash flows from investing activities
Capital expenditures		(388	)		(392	)		(339	)
Change in restricted cash		1			1			1
Other investing activities		10			14			1

Net cash flows used in investing activities		(377	)		(377	)		(337	)

Cash flows from financing activities
Changes in short-term debt		(95	)		(151	)		151
Issuance of long-term debt		250			941			172
Retirement of long-term debt		—			(604	)		(17	)
Retirement of long-term debt to PECO Energy Transition Trust		(709	)		(609	)		(671	)
Changes in Exelon intercompany money pool		—			—			(45	)
Dividends paid on common stock		(312	)		(480	)		(562	)
Dividends paid on preferred securities		(4	)		(4	)		(4	)
Repayment of receivable from parent		320			284			306
Contributions from parent		27			36			32
Other financing activities		(2	)		—			—

Net cash flows used in financing activities		(525	)		(587	)		(638	)

Increase in cash and cash equivalents		264			5			5
Cash and cash equivalents at beginning of period		39			34			29

Cash and cash equivalents at end of period	$	303		$	39		$	34

See the Combined Notes to Consolidated Financial Statements

179

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009		2008
ASSETS

Current assets
Cash and cash equivalents	$	303	$	39
Restricted cash		1		2
Accounts receivable, net
Customer		392		457
Other		120		39
Inventories, net
Fossil fuel		96		172
Materials and supplies		18		18
Deferred income taxes		65		78
Other		11		14

Total current assets		1,006		819

Property, plant and equipment, net		5,297		5,074

Deferred debits and other assets
Regulatory assets		1,834		2,597
Investments		18		15
Investments in affiliates		13		39
Receivable from affiliates		311		47
Other		540		578

Total deferred debits and other assets		2,716		3,276

Total assets	$	9,019	$	9,169

See the Combined Notes to Consolidated Financial Statements

180

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2009			2008
LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities
Short-term borrowings	$	—		$	95
Long-term debt to PECO Energy Transition Trust due within one year		415			319
Accounts payable		164			204
Accrued expenses		74			120
Payables to affiliates		189			144
Customer deposits		65			74
Other		32			25

Total current liabilities		939			981

Long-term debt		2,221			1,971
Long-term debt to PECO Energy Transition Trust		—			805
Long-term debt to other financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,241			2,451
Asset retirement obligations		24			24
Non-pension postretirement benefits obligations		296			283
Regulatory liabilities		317			49
Mark-to-market derivative liabilities		2			—
Mark-to-market derivative liabilities with affiliate		2			—
Other		141			152

Total deferred credits and other liabilities		3,023			2,959

Total liabilities		6,367			6,900

Commitments and contingencies
Preferred securities		87			87
Shareholders’ equity
Common stock		2,318			2,291
Receivable from parent		(180	)		(500	)
Retained earnings		426			389
Accumulated other comprehensive income, net		1			2

Total shareholders’ equity		2,565			2,182

Total liabilities and shareholders’ equity	$	9,019		$	9,169

See the Combined Notes to Consolidated Financial Statements

181

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Changes in Stockholders’ Equity


(In millions)	Common Stock		Receivable from Parent			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance, December 31, 2006	$	2,223	$	(1,090	)	$	584		$	5		$	1,722
Net Income		—		—			507			—			507
Common stock dividends		—		—			(562	)		—			(562	)
Preferred security dividends		—		—			(4	)		—			(4	)
Repayment of receivable from parent		—		306			—			—			306
Allocation of tax benefit from parent		32		—			—			—			32
Adoption of accounting for uncertain tax positions		—		—			23			—			23
Other comprehensive loss, net of income taxes of $(1)		—		—			—			(1	)		(1	)

Balance, December 31, 2007	$	2,255	$	(784	)	$	548		$	4		$	2,023
Net Income		—		—			325			—			325
Common stock dividends		—		—			(480	)		—			(480	)
Preferred security dividends		—		—			(4	)		—			(4	)
Repayment of receivable from parent		—		284			—			—			284
Allocation of tax benefit from parent		36		—			—			—			36
Other comprehensive loss, net of income taxes of $(1)		—		—			—			(2	)		(2	)

Balance, December 31, 2008	$	2,291	$	(500	)	$	389		$	2		$	2,182
Net Income		—		—			353			—			353
Common stock dividends		—		—			(312	)		—			(312	)
Preferred security dividends		—		—			(4	)		—			(4	)
Repayment of receivable from parent		—		320			—			—			320
Allocation of tax benefit from parent		27		—			—			—			27
Other comprehensive loss, net of income taxes of $(1)		—		—			—			(1	)		(1	)

Balance, December 31, 2009	$	2,318	$	(180	)	$	426		$	1		$	2,565

See the Combined Notes to Consolidated Financial Statements

182

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Net Income	$	353		$	325		$	507
Other comprehensive loss
Amortization of realized loss on settled cash flow swaps, net of income taxes of $(1), $0 and $(1), respectively		(1	)		(1	)		(1	)
Change in unrealized loss on marketable securities, net of income taxes of $0, $(1) and $0, respectively		—			(1	)		—

Other comprehensive loss		(1	)		(2	)		(1	)

Comprehensive income	$	352		$	323		$	506

See the Combined Notes to Consolidated Financial Statements

183

Combined Notes to Consolidated Financial Statements

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

1. Significant Accounting Policies (Exelon, Generation, ComEd and PECO)

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

Exelon is a utility services holding company engaged, through its subsidiaries, in the generation and energy delivery businesses discussed below. The generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail supply operations of Generation. The energy delivery businesses include the purchase and regulated retail sale of electricity and the provision of transmission and distribution services by ComEd in northern Illinois, including the City of Chicago, and by 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.

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

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance type costs that cannot be directly assigned are allocated based on a Modified Massachusetts formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred securities. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2009 and December 31, 2008 as equity and PECO’s preferred securities as preferred securities of subsidiaries in its consolidated financial statements.

Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for Exelon SHC, Inc., of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon’s consolidated financial statements. AmerGen, a wholly owned subsidiary of Generation through January 8, 2009, owned and operated the Clinton, Three Mile Island (TMI) Unit No. 1 and Oyster Creek generating stations. Effective January 8, 2009, AmerGen was merged into Generation, and Generation now holds the operating licenses for Clinton, TMI and Oyster Creek and owns and operates those plants.

Each of Generation’s, ComEd’s and PECO’s consolidated financial statements includes the accounts of their subsidiaries. All intercompany transactions have been eliminated.

Certain prior year amounts in Exelon’s, Generation’s and ComEd’s Consolidated Statements of Cash Flows, in Exelon’s and ComEd’s Consolidated Statements of Operations and in Exelon’s and Generation’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect net income or cash flows from operating activities of the Registrants. See Note 8—Derivative Financial Instruments for further discussion of the reclassifications to Exelon’s and Generation’s Consolidated Balance Sheets. The Registrants performed an evaluation

184

Combined Notes to Consolidated Financial Statements—(Continued)

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

of subsequent events for the accompanying financial statements and notes included in Part 2, ITEM 8 of this report through February 5, 2010, the date this Report was issued, to determine whether the circumstances warranted recognition and disclosure of those events or transactions in the financial statements as of December 31, 2009.

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

The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ 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 AROs, pension and other postretirement benefits, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, fixed asset depreciation, environmental costs, taxes 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 ICC and the PAPUC under state public utility laws and the FERC under various Federal laws. Exelon, ComEd and PECO apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd and PECO to record in their consolidated 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 expectation 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 respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd’s or PECO’s business was no longer able to meet the criteria discussed above, Exelon, ComEd and PECO would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which would have a material impact on their results of operations and financial positions. See Note 2—Regulatory Issues for additional information.

Segment Information (Generation, ComEd and PECO)

Exelon has three operating and reportable segments: Generation, ComEd and PECO. See Note 20—Segment Information for additional information regarding Exelon’s segments. Generation, ComEd and PECO each represent a single reportable segment. PECO has two operating segments, electric and gas delivery, which are aggregated into one reportable segment primarily due to their similar economic characteristics and the regulatory environments in which they operate.

Variable Interest Entities (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, and Generation’s and PECO’s proportionate interests in jointly owned electric utility property, after the elimination of

185

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 VIE. 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 method of accounting.

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation’s membership in NEIL are discussed in further detail in Generation’s Note 18—Commitments and Contingencies. Generation has evaluated these contracts and determined that either, it has no variable interest in an entity, or where Generation does have a variable interest in an entity, it is not the primary beneficiary and, therefore, consolidation is not required.

Several of Generation’s long-term PPAs have been determined to be operating leases that have no residual value guarantees, bargain purchase options or other provisions that would cause these operating leases to be variable interests. For contracts where Generation has a variable interest, Generation has considered which interest holder has the power to direct the activities that most significantly impact the economics of the VIE and thus be considered the primary beneficiary and required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities providing the power to direct the entities’ activities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities, under the contracts Generation receives less than the majority of the output of the remaining expected useful life of the facilities, and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Generation’s Note 18—Commitments and Contingencies. Upon consideration of these factors, Generation does not consider it to be the primary beneficiary of these VIEs.

Generation has aggregated its contracts with VIEs into two categories, energy commitments and fuel purchase obligations, based on the similar risk characteristics and significance to Generation. As of the balance sheet date, the carrying amount of assets and liabilities in Generation’s Consolidated Balance Sheet that relate to its involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by Generation for the deliveries associated with the current billing cycle under the contracts. Further, Generation has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts, so there is no significant potential exposure to loss as a result of its involvement with the VIEs.

The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, namely PECO Trust III, PECO Trust IV and PETT, are not consolidated in Exelon’s, ComEd’s and PECO’s financial statements. PETT was created for the sole purpose of issuing debt obligations to securitize intangible transition property of PECO; and the other entities were created to issue mandatorily redeemable trust preferred securities.

186

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd and PECO have concluded that they do not have a variable interest in ComEd Financing III, PECO Trust III or PECO Trust IV as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt. PECO has concluded that it is not the primary beneficiary of PETT because investors in the trust’s securities, not PECO, bear the majority of risk of loss related to those securities. See further discussion regarding the future consolidation of VIEs below under New Accounting Pronouncements.

ComEd and PECO, as the sponsors of the financing trusts are obligated to pay the operating expenses of the trusts. ComEd’s and PECO’s balance sheets include payable to affiliate amounts due to their respective financing trusts as well as investments in their respective trusts. See Note 21—Related-Party Transactions regarding information on the amounts recorded with respect to the financing trusts within the Consolidated Financial Statements.

The maximum exposure to loss as a result of PECO’s involvement with PETT was $7 million at December 31, 2009 and $30 million at December 31, 2008. PECO’s maximum exposure to loss is determined based on the current carrying value of investments made in PETT. PECO has not provided any non-contractually required financial support to PETT during the years ended December 31, 2009 and December 31, 2008. PECO had net undistributed losses of equity method investments related to PETT of $97 million and $73 million at December 31, 2009 and 2008, respectively.

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 3—Accounts Receivable for further information.

RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, Exelon and Generation report sales and purchases conducted on a net hourly basis in either revenues or purchased power on Exelon’s and Generation’s Consolidated Statements of Operations, the classification of which depends on the net hourly activity. ComEd nets its spot market purchases against its spot market sales on an hourly basis, with the result recorded in purchased power expense. In 2009 and 2008, ComEd recorded an immaterial amount associated with hours where it had net spot market sales. ComEd did not record any net spot market sales during 2007.

Option Contracts, Swaps, and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expenses, unless hedge accounting is applied. Premiums received and paid on option contracts are recognized as revenue or expensed over the terms of the contracts. If the derivatives meet hedging criteria, changes in fair value are recorded in OCI. ComEd has not elected hedge accounting for its financial swap contract with Generation. Since ComEd is entitled to full recovery of the costs of the financial swap contract in rates, ComEd records the fair value of the swap as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets.

Trading Activities. Exelon and Generation account for their trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which requires revenue and energy costs related to energy trading contracts to

187

Combined Notes to Consolidated Financial Statements—(Continued)

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

be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues.

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. The Registrants account for uncertain income tax positions using 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 realized upon ultimate settlement, in accordance with the authoritative guidance for accounting for uncertain tax positions. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit is 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. The Registrants recognize accrued interest related to unrecognized tax benefits in interest expense or interest income in other income and deductions on their Consolidated Statements of Operations.

Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 10—Income Taxes for further information.

Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, ComEd and PECO)

Exelon, ComEd and PECO present any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on a gross (included in revenues and costs) basis. See Note 19—Supplemental Financial Information for ComEd’s and PECO’s utility taxes that are presented on a gross basis.

Losses on Reacquired and Retired Debt (Exelon, Generation, ComEd and PECO)

Consistent with rate recovery for ratemaking purposes, ComEd’s and PECO’s recoverable losses on reacquired long-term 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 Exelon’s and Generation’s reacquired debt are recognized as incurred in the Registrants’ Consolidated Statements of Operations.

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

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

Restricted Cash and Investments (Exelon, Generation, ComEd and PECO)

As of December 31, 2009 and 2008, Exelon Corporate’s restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. As of December 31, 2009 and December 31, 2008, Generation’s restricted cash and investments primarily

188

Combined Notes to Consolidated Financial Statements—(Continued)

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

represented restricted funds for qualifying design, engineering and construction costs related to pollution control notes issued by Generation for an emissions-control facilities project and for payment of certain environmental liabilities. As of December 31, 2009 and 2008, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture.

Restricted cash and investments not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2009 and 2008, Exelon and Generation had restricted cash and investments in the NDT funds classified as noncurrent assets. As of December 31, 2009 and 2008, ComEd had short-term investments in Rabbi trusts classified as noncurrent assets.

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

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience and other currently available evidence. ComEd and PECO customers’ 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. ComEd and PECO customers’ accounts are written off consistent with approved regulatory requirements. See Note 2—Regulatory Issues for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.

The following table summarizes the provision for uncollectible accounts for the years ended December 31, 2009, 2008 and 2007:


For the Year Ended December 31,	Exelon		Generation		ComEd		PECO
2009	$	149	$	2	$	85	$	63
2008		247		17		71		160
2007		132		4		58		71

Inventories (Exelon, Generation, ComEd and PECO)

Inventory is recorded at the lower of cost or market. Provisions are recorded 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 or sold.

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 expensed or capitalized to plant, as appropriate, when installed or used.

Emission Allowances. 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. The Exelon and Generation emission allowance balances as of December 31, 2009 and 2008 were $78 million and $80 million, respectively.

Marketable Securities (Exelon, Generation, ComEd and PECO)

All marketable securities are reported at fair value. Marketable securities held in the NDT funds are classified as trading securities and all securities that are not held by the NDT funds are classified

189

Combined Notes to Consolidated Financial Statements—(Continued)

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

as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the former ComEd and former PECO nuclear generating units (Regulatory Agreement Units) are included in regulatory liabilities at Exelon, ComEd, and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the former AmerGen nuclear generating units and the unregulated portions of the Peach Bottom nuclear generating units (Non-Regulatory Agreement Units) are included in earnings at Exelon and Generation. Unrealized gains and losses, net of tax, for ComEd’s and PECO’s available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd’s and PECO’s available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 7—Fair Value of Financial Assets and Liabilities for further information regarding the other-than-temporary impairment recorded in the second quarter of 2009 by Exelon and ComEd related to ComEd’s Rabbi trust investments. See Note 11—Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 19—Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities.

Deferred Energy Costs (Exelon, ComEd and PECO)

ComEd’s electricity and transmission costs are recoverable or refundable under ComEd’s ICC and/or FERC approved retail rates. ComEd recovers or refunds the difference between the actual cost of electricity and transmission and the amount included in rates charged to its customers. 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 monthly adjustments to rates.

PECO’s natural gas rates are subject to a purchased gas cost 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.

See Note 19—Supplemental Financial Information for additional information regarding deferred energy costs for Exelon, ComEd and PECO.

Leases (Exelon, Generation, ComEd and PECO)

At the inception of a contract determined to be a lease, or as a result of a 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 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.

Property, Plant and Equipment (Exelon, Generation, ComEd and PECO)

Property, plant and equipment is recorded at original cost. Original cost includes labor and materials, construction overhead, when appropriate, capitalized interest and AFUDC, for regulated

190

Combined Notes to Consolidated Financial Statements—(Continued)

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

property at ComEd and PECO. The cost of repairs and maintenance, including planned major maintenance activities 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 in accordance with the composite method of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, is capitalized when incurred to gross plant as part cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs and salvage incurred for property that will not be replaced is charged to expense as incurred.

For ComEd and PECO, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd’s depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement as these costs, as well as depreciation expense, are included in cost of service for rate-making purposes. ComEd’s removal costs reduce the related regulatory liability. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.

See Note 4—Property, Plant and Equipment, Note 5—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 SNF is established per the Standard Waste Contract with the DOE and is expensed through fuel expense at one mill ($.001) per kWh of net nuclear generation. On-site SNF storage costs are capitalized or expensed as incurred based upon the nature of the work performed. A portion of the storage costs are being reimbursed by the DOE since a DOE (or government owned) long-term storage facility has not been completed. See Note 12—Spent Nuclear Fuel Obligation for additional information.

Nuclear Outage Costs (Exelon and Generation)

Costs associated with nuclear outages, including planned major maintenance activities, are recorded in the period incurred.

New Site Development Costs (Exelon and Generation)

New site development costs represent the costs incurred in the assessment, design and construction of new power generating stations. Such costs are capitalized when management considers project completion to be likely, primarily based on management’s determination that the project is economically and operationally feasible, management and the Board of Directors have approved the project and have committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Through the year ended December 31, 2009, there have been no significant costs capitalized related to new site development; however, approximately $23 million, $26 million and $48 million of costs were expensed by Generation for the years ended December 31, 2009, 2008 and 2007, respectively, related to the possible construction of a new nuclear plant in Texas.

191

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 five years. Certain other capitalized software costs are being amortized over longer lives, pursuant to regulatory approval or requirement. 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, 2009	$	279	$	67	$	123	$	55
December 31, 2008		259		45		106		55


Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO
2009	$	105	$	24	$	29	$	15
2008		91		21		29		13
2007		79		19		24		11

Depreciation and Amortization (Exelon, Generation, ComEd and PECO)

Except for the amortization of nuclear fuel, depreciation is generally recorded 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. The estimated service lives for ComEd and PECO are primarily based on the average service lives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities are based on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent that such renewal has not yet been granted) for all of Generation’s operating nuclear generating stations. The estimated service lives of the fossil fuel generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments as well as economic and capital requirements. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. See Note 4—Property, Plant and Equipment for further information regarding depreciation.

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 additional information regarding Generation’s nuclear fuel, Generation’s ARC and the amortization of ComEd’s and PECO’s regulatory assets.

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

The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement is conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios based upon significant estimates and assumptions, including decommissioning cost studies, cost escalation studies, probabilistic cash flow models and discount rates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years. Generation generally updates its ARO annually

192

Combined Notes to Consolidated Financial Statements—(Continued)

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

based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing basis due to the passage of new laws and regulations and revisions to either the timing or amount of estimates of undiscounted cash flows and estimates of cost escalation factors. AROs are accreted each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations or, in the case of the majority of ComEd’s and PECO’s accretion, through an increase to regulatory assets. See Note 11—Asset Retirement Obligations for additional information.

Capitalized Interest and AFUDC (Exelon, Generation, ComEd and PECO)

Exelon and Generation capitalize the costs of debt funds during construction used to finance non-regulated construction projects.

Exelon, ComEd and PECO apply the authoritative guidance for accounting for certain types of regulation to calculate 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.

The following table summarizes total cost incurred, capitalized interest and credits of AFUDC by year:


		Exelon		Generation		ComEd			PECO
2009	Total incurred interest ^(a)	$	786	$	162	$	322		$	189
	Capitalized interest		50		49		—			—
	Credits to AFUDC debt and equity		14		—		8			6

2008	Total incurred interest ^(a)	$	867	$	170	$	344		$	229
	Capitalized interest		34		33		—			—
	Credits to AFUDC debt and equity		2		—		(1	)		3

2007	Total incurred interest ^(a)	$	896	$	196	$	331		$	251
	Capitalized interest		30		30		—			—
	Credits to AFUDC debt and equity		19		—		16			3

(a)	Includes interest expense to affiliates.

Guarantees (Exelon, Generation, ComEd and PECO)

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 release from risk of the Registrant 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. See Note 18—Commitments and Contingencies for additional information.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Asset Impairments (Exelon, Generation, ComEd and PECO)

Long-Lived Assets. 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. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, including current energy and market conditions, condition of the asset, specific regulatory disallowance or plans to dispose of a long-lived asset significantly before the end of its useful life. 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 evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets are largely independent of other groups of assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units. For ComEd and PECO, the lowest level of independent cash flows is determined by evaluation of several factors including the ratemaking jurisdiction in which they operate and the type of service or commodity. For ComEd the lowest level of independent cash flows is transmission and distribution and for PECO, the lowest level of independent cash flows is transmission, distribution and gas. Impairment may occur when the carrying value of the asset or asset group exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. An impairment would require the affected Registrant to reduce both the long-lived asset and current period earnings by the amount of the impairment. See Note 4—Property, Plant and Equipment for a discussion of asset impairment evaluations made by Generation.

Exelon holds certain investments in direct financing leases. Exelon determines the investment in direct financing leases by incorporating an estimate of the residual values of the leased assets. On an annual basis, Exelon reviews the estimated residual values of these leased assets to determine if the current estimate of their residual value is lower than the one used at the start of the lease. In determining the estimate of the residual value the expectation of future market conditions, including commodity prices, is considered. If the estimated residual value is lower than at the start of the lease and the decline is considered to be other than temporary, a loss will be recognized with a corresponding reduction to the carrying amount of the investment. To date, no such losses have been recognized.

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. 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 could reduce the fair value of a reporting unit below its carrying value. See Note 6—Intangible Assets for additional information regarding Exelon’s and ComEd’s goodwill.

Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that

194

Combined Notes to Consolidated Financial Statements—(Continued)

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

qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges 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). For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon’s Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel, or other, net on the Consolidated Statements of Operations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statement of Cash Flows, depending on the underlying nature of the Registrants’ hedged items.

Revenues and expenses on contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and price is not tied to an unrelated underlying derivative. 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. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings at Generation or offset by a regulatory asset or liability at ComEd and PECO. See Note 8—Derivative Financial Instruments for additional information.

Retirement Benefits (Exelon, Generation, ComEd and PECO)

Exelon’s defined benefit pension plans and postretirement benefit plans are accounted for and disclosed in accordance with applicable authoritative guidance. Generation, ComEd and PECO participate in Exelon’s defined benefit pension plans and postretirement plans. AmerGen sponsored a separate defined benefit pension plan and postretirement plan for its employees until the merger of AmerGen into Generation on January 8, 2009. Exelon became the sponsor of those plans at that date.

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes on pension and other postretirement benefit obligations is generally recognized over the expected average remaining service period of the employees rather than immediately recognized in the income statement.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Treasury Stock (Exelon)

Treasury shares are recorded at cost. Any shares of common stock repurchased are held as treasury shares unless cancelled or reissued.

New Accounting Pronouncements (Exelon, Generation, ComEd and PECO)

Exelon has identified the following new accounting pronouncements that have been recently adopted or issued that may affect the Registrants upon adoption.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007 (and clarified in January 2010), the FASB issued authoritative guidance clarifying that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. With certain exceptions, this guidance requires that a change in a parent’s ownership interest in a subsidiary be reported as an equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent’s ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated financial statements. This guidance was applied prospectively as of January 1, 2009, except for the presentation and disclosure requirements, which were applied retrospectively for all periods presented.

The adoption had no impact on Exelon’s consolidated financial statements. Generation reclassified its noncontrolling interest of a consolidated subsidiary from mezzanine equity to equity in its Consolidated Balance Sheets and Statements of Changes in Member’s Equity for all periods presented. The noncontrolling interest is eliminated in Exelon’s consolidated financial statements as it is owned by Exelon.

PECO reclassified preferred securities from shareholders’ equity to mezzanine equity within its Consolidated Balance Sheets for all periods presented and separately reflects its preferred security dividends on its Statement of Operations. On Exelon’s Consolidated Statements of Operations and Comprehensive Income, the dividends on PECO’s preferred securities are included in interest expense and have not been reflected separately as the amounts are not considered significant.

Derivative Instrument and Hedging Activity Disclosures

In March 2008, the FASB amended and expanded the disclosure requirements related to derivative instruments and hedging activities by requiring enhanced disclosures about how and why an

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Combined Notes to Consolidated Financial Statements—(Continued)

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

entity uses derivative instruments, how an entity accounts for derivative instruments and related hedged items and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The revised guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. This guidance was effective for the Registrants as of January 1, 2009. Since this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 8—Derivative Financial Instruments for further information.

Pension and Other Postretirement Benefit Plan Asset Disclosures

In December 2008, the FASB issued authoritative guidance requiring additional disclosures for employers’ pension and other postretirement benefit plan assets. This guidance requires employers to disclose information about fair value measurements of plan assets, the investment policies and strategies for the major categories of plan assets, and significant concentrations of risk within plan assets. This guidance became effective for the Registrants as of December 31, 2009. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 13—Retirement Benefits for further information.

Fair Value Measurements

The FASB’s fair value measurement and disclosure guidance for all nonrecurring fair value measurements of nonfinancial assets and liabilities became effective for the Registrants as of January 1, 2009. See Note 7—Fair Value of Financial Assets and Liabilities for further information.

In April 2009, the FASB issued authoritative guidance clarifying that fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. This new guidance requires an evaluation of whether there has been a significant decrease in the volume and level of activity for the asset or liability in relation to normal market activity for the asset or liability. If there has, transactions or quoted prices may not be indicative of fair value and an adjustment may need to be made to those prices to estimate fair value. Additionally, an entity must consider whether the observed transaction was orderly (i.e. not distressed or forced). If the transaction was orderly, the obtained price can be considered a relevant observable input for determining fair value. If the transaction is not orderly, other valuation techniques must be used when estimating fair value. This guidance was adopted for the period ending June 30, 2009. The adoption of this guidance did not have a material impact to the Registrants’ results of operations, cash flows or financial positions.

In August 2009, the FASB issued authoritative guidance clarifying the measurement of the fair value of a liability in circumstances when a quoted price in an active market for an identical liability is not available. The guidance emphasizes that entities should maximize the use of observable inputs in the absence of quoted prices when measuring the fair value of liabilities. This guidance became effective for the Registrants as of October 1, 2009 and did not have a material impact on the Registrants’ results of operations, cash flows or financial positions.

197

Combined Notes to Consolidated Financial Statements—(Continued)

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

In September 2009, the FASB issued authoritative guidance that provides further clarification for measuring the fair value of investments in entities that meet the FASB’s definition of an investment company. This guidance permits a company to estimate the fair value of an investment using the NAV per share of the investment if the NAV is determined in accordance with the FASB’s guidance for investment companies as of the company’s measurement date. This creates a practical expedient to determining a fair value estimate and allows certain attributes of the investment (such as redemption restrictions) to not be considered in measuring fair value. Additionally, companies with investments within the scope of this guidance must disclose additional information related to the nature and risks of the investments. This guidance became effective for the Registrants as of December 31, 2009 and is required to be applied prospectively. Exelon’s pension and other postretirement benefit plan assets and Generation’s NDT fund investments contain certain investments, including alternative investments and commingled funds, which are within the scope of this guidance. As a result of the issuance of this guidance, Exelon and Generation reclassified investments in NDT commingled funds from Level 3 in the fair value hierarchy to Level 2 in the fair value hierarchy. However, as the fair value of these investments was already determined based on NAVs per fund share, this guidance did not have a material impact on the Registrants’ results of operations, cash flows or financial positions. See Note 13—Retirement Benefits and Note 7—Fair Value of Financial Assets and Liabilities for further information.

Fair Value of Financial Instruments Disclosures

In April 2009, the FASB issued revised authoritative guidance requiring disclosures about fair value of financial instruments, currently provided annually, to be included in interim financial statements. This guidance was adopted by the Registrants for the period ended June 30, 2009. Since this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 7—Fair Value of Financial Assets and Liabilities for further information.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB amended authoritative guidance related to accounting for certain investments in debt and equity securities and accounting for certain investments held by not-for-profit organizations. This revised guidance establishes a new method of recognizing and reporting other-than-temporary impairments of debt securities. If it is more likely than not that an impaired debt security will be sold before the recovery of its cost basis, either due to the investor’s intent to sell or because it will be required to sell the security, the entire impairment is recognized in earnings. Otherwise, only the portion of the impaired debt security related to estimated credit losses is recognized in earnings, while the remainder of the impairment is recorded in OCI and recognized over the remaining life of the debt security. In addition, the guidance expands the presentation and disclosure requirements for other- than-temporary impairments for both debt and equity securities. This guidance was adopted for the period ended June 30, 2009 and did not have a material impact on the Registrants’ results of operations, cash flows or financial positions. See Note 7—Fair Value of Financial Assets and Liabilities for further information.

Subsequent Events

In May 2009, the FASB issued authoritative guidance which incorporates the principles and accounting guidance for recognizing and disclosing subsequent events that originated as auditing standards into the body of authoritative literature issued by the FASB and prescribes disclosures

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Combined Notes to Consolidated Financial Statements—(Continued)

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

regarding the date through which subsequent events have been evaluated. The Registrants are required to evaluate subsequent events through the date the financial statements are issued. This guidance was effective for the Registrants for the period ended June 30, 2009. Since this guidance is not intended to significantly change the current practice of reporting subsequent events, it did not have an impact on the Registrants’ results of operations, cash flows or financial positions.

Transfers of Financial Assets

In June 2009, the FASB issued authoritative guidance amending the accounting for the transfers of financial assets. Key provisions include (i) the removal of the concept of qualifying special purpose entities, (ii) the introduction of the concept of a participating interest, in circumstances in which a portion of a financial asset has been transferred and (iii) the requirement that to qualify for sale accounting, the transferor must evaluate whether it maintains effective control over transferred financial assets either directly or indirectly. Furthermore, this guidance requires enhanced disclosures about transfers of financial assets and a transferor’s continuing involvement. This guidance is effective for the Registrants beginning January 1, 2010 and is required to be applied prospectively. Currently, PECO’s agreement related to the sale of accounts receivable is accounted for as a sale. Under the new guidance, this agreement will be accounted for as a secured borrowing. As a result, beginning in the first quarter of 2010, the transferred accounts receivable of $225 million under this agreement will be recorded on PECO’s balance sheet with an offsetting short-term note payable of $225 million.

Consolidation of Variable Interest Entities

In June 2009, the FASB issued authoritative guidance to amend the manner in which entities evaluate whether consolidation is required for VIEs. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Previously, variable interest holders had to determine whether they had a controlling financial interest in a VIE based on a quantitative analysis of the expected gains and/or losses of the entity. In contrast, the new guidance requires an enterprise with a variable interest in a VIE to qualitatively assess whether it has a controlling financial interest in the entity, and if so, whether it is the primary beneficiary. Furthermore, this guidance requires that companies continually evaluate VIEs for consolidation rather than assessing based upon the occurrence of triggering events. This revised guidance also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. This guidance became effective for the Registrants on January 1, 2010. As a result of the issuance of this new guidance, PECO consolidated PETT effective January 1, 2010. The consolidation of PETT had no impact on PECO’s results of operations. As of January 1, 2010, Exelon’s and PECO’s Consolidated Balance Sheets reflect PETT’s restricted cash of $413 million and $805 million for PETT’s long-term debt due to bondholders. PECO’s investment in PETT and long-term debt to PETT was eliminated in consolidation. The new guidance had no effect on ComEd. Generation does not anticipate a significant impact from the adoption of this accounting standard; however, due to evolving interpretations of this guidance, Generation has not fully completed its assessment.

Accounting Standards Codification

In June 2009, the FASB issued authoritative guidance which replaced the previous hierarchy of GAAP and establishes the FASB Codification as the single source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. SEC rules and interpretive releases are also

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Combined Notes to Consolidated Financial Statements—(Continued)

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

sources of authoritative GAAP for SEC registrants. This guidance modifies the GAAP hierarchy to include only two levels of GAAP: authoritative and nonauthoritative. This guidance was effective for the Registrants as of September 30, 2009. The adoption of this guidance did not impact the Registrants’ results of operations, cash flows or financial positions since the FASB Codification is not intended to change or alter existing GAAP.

Revenue Arrangements with Multiple Deliverables

In October 2009, the FASB issued authoritative guidance that amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. The guidance is expected to result in more multiple-deliverable arrangements being separable than under current guidance. This guidance is effective for the Registrants beginning on January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. The Registrants are currently assessing the impacts this guidance may have on their consolidated financial statements.

Fair Value Measurements Disclosures

In January 2010, the FASB issued authoritative guidance intended to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels and the reasons for the transfers and to present information about purchases, sales, issuances and settlements separately in the reconciliation of fair value measurements using significant unobservable inputs (Level 3). Additionally, the guidance clarifies that a reporting entity should provide fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurements using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). This guidance is effective for interim and annual periods beginning after December 15, 2009 except for the disclosures about purchases, sales, issuances and settlements in the Level 3 reconciliation, which will be effective for interim and annual periods beginning after December 15, 2010. As this guidance provides only disclosure requirements, the adoption of this standard will not impact the Registrants’ results of operations, cash flows or financial positions.

2. Regulatory Issues (Exelon, Generation, ComEd and PECO)

Illinois Settlement Agreement (Exelon, Generation and ComEd). In July 2007, following extensive discussions with legislative leaders in Illinois, ComEd, Generation and other utilities and generators in Illinois reached an agreement (Illinois Settlement) with various parties concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Legislation reflecting the Illinois Settlement (Illinois Settlement Legislation) was signed into law in August 2007. The Illinois Settlement and the Illinois Settlement Legislation provide for the following, among other things:

Rate Relief Programs

•

Various Illinois electric utilities, their affiliates and generators of electricity in Illinois agreed to contribute approximately $1 billion over a period of four years (2007-2010) to programs to provide rate relief to Illinois electricity customers and funding for the IPA created by the Illinois

200

Combined Notes to Consolidated Financial Statements—(Continued)

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

Settlement Legislation. ComEd committed to issue $64 million in rate relief credits to customers or to fund various programs to assist customers. Generation committed to contribute an aggregate of $747 million, consisting of $435 million to pay ComEd for rate relief programs for ComEd customers, $307.5 million for rate relief programs for customers of other Illinois utilities and $4.5 million for partially funding operations of the IPA. The contributions are recognized in the financial statements of Generation and ComEd as rate relief credits are applied to customer bills by ComEd and other Illinois utilities or as operating expenses associated with the programs are incurred.

During the years ended December 31, 2009, 2008 and 2007, Generation and ComEd recognized net costs from their contributions pursuant to the Illinois Settlement in their Consolidated Statements of Operations as follows:


Year Ended December 31, 2009	Generation		ComEd		Total Credits Issued to ComEd Customers
Credits to ComEd customers^(a)	$	45	$	8	$	53
Credits to other Illinois utilities’ customers ^(a)		53		n/a		n/a
Other rate relief programs ^(b)		—		1		n/a

Total incurred costs	$	98	$	9	$	53


Year Ended December 31, 2008	Generation		ComEd		Total Credits Issued to ComEd Customers
Credits to ComEd customers^(a)	$	131	$	6	$	137
Credits to other Illinois utilities’ customers ^(a)		90		n/a		n/a
Other rate relief programs ^(b)		—		7		n/a

Total incurred costs	$	221	$	13	$	137


Year Ended December 31, 2007	Generation		ComEd		Total Credits Issued to ComEd Customers
Credits to ComEd customers^(a)	$	246	$	33	$	279
Credits to other Illinois utilities’ customers^(a)		157		n/a		n/a
Other rate relief programs ^(b)		—		8		n/a
Funding of the IPA ^(a)		5		—		n/a

Total incurred costs	$	408	$	41	$	279

(a)	Recorded as a reduction in operating revenues

(b)	Recorded as a charge to operating and maintenance expense

As of December 31, 2009, Generation’s remaining costs to be recognized related to the rate relief commitment are $20 million, consisting of $13 million related to programs for ComEd customers and $7 million for programs for customers of other Illinois utilities. ComEd’s remaining costs to be recognized related to the rate relief commitment are $1 million as of December 31, 2009.

Energy Efficiency and Renewable Energy

•

Electric utilities in Illinois are required to include cost-effective energy efficiency resources in their plans to meet an incremental annual program energy savings requirement of 0.2% of energy delivered to retail customers for the year ended June 1, 2009, which increases annually to 2% of energy delivered in the year commencing June 1, 2015 and each year thereafter.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Additionally, during the ten year period that began June 1, 2008, electric utilities must implement cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject to rate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. In February 2008, the ICC issued an order approving substantially all of ComEd’s Energy Efficiency and Demand Response Plan, including cost recovery. This plan began in June 2008 and is designed to meet the Illinois Settlement Legislation’s energy efficiency and demand response goals for an initial three-year period, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers. During the years ended December 31, 2009 and 2008, expenses related to energy efficiency and demand response programs consisted of $59 million and $25 million, respectively.

•

Since June 1, 2008, utilities have been required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that will cumulatively increase this percentage to at least 10% by June 1, 2015, with an ultimate target of at least 25% by June 1, 2025, subject to customer rate cap limitations. All goals are subject to rate impact criteria set forth in the Illinois Settlement Legislation. Under a May 2008 ICC-approved RFP, ComEd procured RECs for the period June 2008 through May 2009. On May 13, 2009, the ICC approved the results of an RFP to procure RECs for the period June 2009 through May 2010. ComEd currently retires all RECs immediately upon purchase. Since June 2008, ComEd recovers procurement costs of RECs through rates. See Note 18—Commitments and Contingencies for further information regarding ComEd’s procurement of RECs.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Beginning on January 1, 2007, ComEd procured 100% of energy to meet its load service requirements through ICC-approved staggered SFCs with various suppliers, including Generation. For the period from June 2008 to May 2009, the ICC approved an interim procurement plan under which ComEd procured energy to meet its load service requirements through an RFP for standard wholesale products, existing SFC and spot market purchases hedged by a five-year variable to fixed financial swap contract with Generation.

Beginning in June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply. On January 7, 2009, the ICC approved the IPA’s plan for procurement of ComEd’s expected energy requirements from June 2009 through May 2010, which includes approximately 38% of ComEd’s expected energy requirements purchased through the spot market and hedged by the financial swap contract with Generation. The remainder of ComEd’s expected energy requirements will be met through the existing SFC and standard products purchased as a result of the 2009 RFP process completed in May 2009. In addition, approximately 9% of ComEd’s energy requirements from June 2010 through May 2011 were procured through the 2009 RFP process.

On September 30, 2009, the IPA filed its procurement plan with the ICC covering June 2010 through May 2015. On December 28, 2009, the ICC approved this plan which will result in approximately 66% of ComEd’s expected energy purchases for the June 2010 to May 2011 period

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Combined Notes to Consolidated Financial Statements—(Continued)

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

being purchased through the spot market and hedged by the financial swap contract with Generation. The remainder of ComEd’s expected energy purchases would be met through the purchases of standard products in the 2009 and 2010 RFP processes. The IPA’s plan also includes a provision for procurement of approximately 3.5% of ComEd’s fixed-price load requirements from renewable energy resources utilizing long-term contracts beginning June 2012. The long term renewables purchased would count towards satisfying ComEd’s obligation under the state’s RPS. See Note 8—Derivative Financial Instruments for further discussion on the financial swap contract.

The ICC has initiated a proceeding to reconcile the actual costs of power purchased in the January 2007 through May 2008 period with the costs for power that flowed through ComEd’s tariffs and were collected from customers. Because the Illinois Settlement Legislation has already deemed such costs to be prudently incurred, the reconciliation proceeding is not expected to have a significant impact on ComEd.

2005 Rate Case (Exelon and ComEd). In August 2005, ComEd filed a rate case with the ICC to comprehensively revise its tariffs and to adjust rates for delivering electricity effective January 2007 (2005 Rate Case). ComEd proposed a revenue increase of $317 million. During 2006, the ICC issued various orders associated with this case, which resulted in a total annual rate increase of $83 million effective January 2007. ComEd and various other parties appealed the rate order to the courts. In September 2009, the Appellate Court of Illinois affirmed the ICC’s order and denied the appeals. Several parties have asked the Appellate Court to rehear various rate design issues addressed in the opinion. There is no set time in which the Court must act.

Original Cost Audit (Exelon and ComEd). In connection with ComEd’s 2005 Rate Case proceeding, the ICC, with ComEd’s concurrence, ordered an “original cost” audit of ComEd’s distribution assets. In December 2007, the consulting firm completed the audit. The consulting firm’s results of the audit were reported to the ICC in April 2008, which presented its findings regarding accounting methodology, documentation and other matters, along with proposed adjustments. The audit report recommended gross plant disallowances of approximately $350 million, before reflecting accumulated depreciation. The basis for the disallowance recommendation on approximately $80 million of the costs was that the assets were misclassified between ComEd’s distribution and transmission operations. ComEd reclassified these costs in September 2007 and they were reflected correctly in ComEd’s rate case filed in October 2007 (2007 Rate Case).

In April 2008, ComEd and the ICC Staff reached a stipulation (the stipulation) regarding various portions of contested issues in the Original Cost Audit as well as the 2007 Rate Case and agreed to make various joint recommendations to the ICC in the 2007 Rate Case. In September 2008, the ICC issued an order in the 2007 Rate Case, which reflected the joint recommendations made by the ICC Staff and ComEd and required ComEd to incur a charge of approximately $19 million (pre-tax) related to various items identified in the Original Cost Audit.

The ICC opened a proceeding on the Original Cost Audit in May 2008. Under the terms of the stipulation, the ICC Staff agreed not to advocate that any of the proposed adjustments in the audit report be adopted other than those reflected in the 2007 Rate Case; however, the stipulation does not preclude other parties to the rate case or to the Original Cost Audit proceeding from taking positions contrary to the stipulation. The Illinois Attorney General submitted testimony and legal briefs suggesting that ComEd improperly changed the way it capitalized certain cable faults during the rate freeze period and therefore the rate base should be reduced by $121 million and ComEd should refund at least $42 million to customers. On January 12, 2010, the ICC issued an order rejecting the Illinois Attorney General’s recommendations in their entirety. The order is subject to rehearing and appeal.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

2007 Rate Case (Exelon and ComEd). ComEd filed the 2007 Rate Case with the ICC for approval to increase its delivery service revenue requirement by approximately $360 million. The ICC issued an order in the rate case approving a $274 million increase in ComEd’s annual revenue requirement, which became effective in September 2008. ComEd and several other parties have filed appeals of the rate order with the courts. ComEd cannot predict the timing of resolution or the results of the appeals. In the event the order is ultimately changed, the changes are expected to be prospective.

The 2007 Rate Case filing also included a system modernization rider, which the ICC approved for the limited purpose of implementing a pilot program for AMI. The rider permits investments in AMI to be reflected in rates on a quarterly basis instead of waiting for the next rate case to begin recovery. On June 1, 2009, ComEd filed its proposed AMI pilot program with the ICC, which included revisions to the system modernization rider. On October 14, 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs under the rider. The AMI pilot program allows ComEd to study the costs and benefits related to automated metering and to develop the cost estimate of full system-wide implementation of AMI. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and lower energy bills. The Illinois Attorney General has appealed the ICC order approving the plan. The matter is not yet briefed.

In August 2009, ComEd filed a request for $175 million of matching Federal stimulus grants with the DOE under the ARRA of 2009 to help finance AMI and Smart Grid technologies in Illinois; however, ComEd did not receive any of the matching grant awards announced by DOE in October 2009.

Transmission Rate Case (Exelon and ComEd). ComEd’s transmission rates are established based on a formula that was approved by FERC in January 2008. FERC’s order establishes the agreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formula rate calculation on an annual basis.

ComEd’s most recent annual formula rate update filed in May 2009 reflects actual 2008 expenses and investments plus forecasted 2009 capital additions. The time for parties to challenge the update has expired; no parties have raised challenges and ComEd will move to close the docket. The update resulted in a revenue requirement of $436 million resulting in an increase of approximately $6 million from the 2008 revenue requirement, plus an additional $4 million related to the 2008 true-up of actual costs. The 2009 revenue requirement of $440 million, which includes the 2008 true-up, became effective June 1, 2009 and is recovered over the period extending through May 31, 2010. The regulatory asset associated with the true-up is being amortized as the associated revenues are received. ComEd will continue to reflect its best estimate of its anticipated true-up in the financial statements.

Illinois Legislation for Recovery of Uncollectible Accounts (Exelon and ComEd). Comprehensive legislation has been enacted in Illinois that provides utilities the ability to adjust their rates annually through a rider mechanism to reflect the increases or decreases in annual uncollectible accounts expenses starting with 2008 and prospectively. ComEd under-collected approximately $26 million during 2008 and approximately $44 million during 2009. On September 8, 2009, ComEd filed a proposed tariff in accordance with the legislation. On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs, with minor modifications.

With the ICC approval of the tariff, ComEd is required to make a one-time contribution of approximately $10 million to the Supplemental Low-Income Energy Assistance Fund (the Fund). The

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Fund is used to assist low-income residential customers. As one way to assist such customers, the legislation creates a new percentage of income payment program (PIPP) that includes an arrearage reduction component for participating customers. The program will be paid for from the Fund and other state monies.

As a result of the ICC order, ComEd will record the $70 million benefit and the $10 million one-time charge in the first quarter of 2010. ComEd will record a regulatory asset and an offsetting reduction in operating and maintenance expense for the cumulative under-collections from 2008 and 2009. Recovery of the initial regulatory asset will take place over an approximate 14-month time frame beginning in April 2010.

Pennsylvania Gas Distribution Rate Case (Exelon and PECO). In October 2008, the PAPUC voted to approve the joint settlement related to PECO’s March 2008 filing providing for an increase of $77 million to its annual natural gas distribution revenue. As part of the settlement, PECO agreed to enhance its low-income programs as well as provide funding for new energy-efficiency programs to help customers manage their energy usage and gas bills. Additionally, PECO agreed not to file a new base rate case for natural gas distribution service before January 1, 2010. The approved rate adjustment became effective on January 1, 2009.

Pennsylvania Transition-Related Legislative and Regulatory Matters (Exelon, Generation and PECO). In Pennsylvania, despite the recent decline in wholesale electricity market prices, there has been some continuing interest from elected officials in mitigating the potential impact of electric generation price increases on customers when rate caps expire. While PECO’s retail electric generation rate cap transition period does not end until December 31, 2010, transition periods have ended for seven other Pennsylvania electric distribution companies and, in most instances, post-transition electric generation price increases occurred. Over the past few years, elected officials in Pennsylvania have worked on developing legislation to address concerns over post-transition electric generation price increases. Measures suggested by legislators include rate-increase deferrals and phase-ins, rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate-relief programs.

On March 12, 2009, the PAPUC approved the settlement of PECO’s Market Rate Transition Phase-In Program. The program allows eligible residential and small-business electric-service customers to transition to market-priced generation through pre-payments made through 2010 that accrue interest at the statutory rate of 6% and are to be applied as credits to their bills in 2011 and 2012. Total collections under this program were not significant as of December 31, 2009.

On June 9, 2009, the PAPUC entered an order instituting an investigation into whether PECO’s nuclear decommissioning cost adjustment clause, which is a mechanism that allows PECO to recover costs from customers for the decommissioning of seven former PECO nuclear units now owned by Generation, should continue after the termination of PECO’s competitive transition cost collections on December 31, 2010 and assigned the matter for alternative dispute resolution or the prompt scheduling of such hearings as may be necessary. On October 14, 2009, a prehearing conference was held and PECO agreed to report to the ALJ on settlement progress. Settlement discussions continue and PECO has been providing the ALJ with periodic reports on settlement progress. See Note 11—Asset Retirement Obligations for additional information.

Pennsylvania Procurement Proceedings (Exelon and PECO). On June 2, 2009, the PAPUC entered an order approving the settlement of PECO’s DSP Program, under which PECO will provide

205

Combined Notes to Consolidated Financial Statements—(Continued)

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

default electric service following the expiration of electric generation rate caps on December 31, 2010. The DSP Program, which has a 29-month term beginning January 1, 2011 and ending May 31, 2013, complies with electric supply procurement guidelines set forth in Act 129. Under the settlement, PECO will also expand its low-income assistance initiatives and offer a market rate deferral program under which certain customers can elect to phase-in, with interest, any post-electric generation rate cap increases in 2011 if they exceed 25%.

PECO’s default electric service customers have been divided into four procurement classes: a residential class, a small commercial class (for non-residential customers with peak demand up to 100 kW), a medium commercial class (for non-residential customers with peak demand of greater than 100 kW up to 500 kW) and a large commercial and industrial class (for non-residential customers with peak demand in excess of 500 kW).

Seventy-five percent of the residential class load, 90% of the small commercial class load and 85% of the medium commercial class load will be served through competitively procured contracts for load-following, fixed price full requirements default electric supply. For the remaining portion of the residential class load, PECO will competitively procure through block contracts, which represent 20% of the load and will balance the remaining load through sales and purchases of energy in the PJM day-ahead wholesale “spot” energy market (spot market). For the remaining portion of the small commercial and medium commercial class loads, as well as the large commercial and industrial class load, PECO will competitively procure contracts for load-following, full requirements default electric supply with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In addition, PECO will offer large commercial and industrial customers a fixed-price optional service during the first year of PECO’s DSP Program.

In 2009, PECO completed two competitive procurements in accordance with the DSP Program for electric supply for default electric service customers commencing January 2011. As of December 31, 2009, PECO has entered into contracts with terms of 17 to 29 months covering 49% of planned full requirements contracts for the residential customer class, contracts with 17-month terms covering 24% of planned full requirements contracts for the small commercial customer class and contracts with 17-month terms covering 16% of planned full requirements contracts for the medium commercial customer class. PECO also entered into block contracts with 12-month terms for a total of 80 MW for service to the residential customer class in 2011. PECO will conduct seven additional competitive procurements in accordance with the DSP Program.

Smart Meter and Smart Grid Investments (Exelon and PECO). PECO is planning to spend up to approximately $650 million on its smart meter and smart grid infrastructure. On November 25, 2009, PECO filed a joint petition for partial settlement of its $550 million Smart Meter Procurement and Installation Plan with the PAPUC, which was filed on August 14, 2009 in accordance with the requirements of Act 129. PECO is requesting PAPUC approval to install more than 1.6 million smart meters and deploy advanced communication networks over a 15 year period. The first phase of the plan includes the procurement and deployment of automated meter infrastructure and an initial deployment of 100,000 smart meters over the next three years. On January 28, 2010, the ALJ issued an initial decision approving the partial settlement and determining remaining cost allocation issues subject to final PAPUC approval. PECO plans to file for PAPUC approval of an initial dynamic pricing and customer acceptance program in June 2010 and for approval of a universal meter deployment plan for its remaining customers in 2012.

206

Combined Notes to Consolidated Financial Statements—(Continued)

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

On August 6, 2009, PECO filed with the DOE an application seeking $200 million in ARRA of 2009 matching grant funds under the Smart Grid Investment Grant Program. PECO’s “Smart Future Greater Philadelphia” project will increase the number of smart meters initially installed to 600,000, accelerate universal smart meter deployment by five years and increase Smart Grid investments up to approximately $100 million over the next three years. On October 27, 2009, the DOE announced its intent to award PECO a $200 million stimulus grant to fund its smart meter and smart grid investments. Assuming successful completion of the DOE negotiations and PECO’s receipt of the full award on reasonable terms, PECO is committed to implementing expanded initial deployment of 600,000 smart meters within three years and then accelerating universal smart meter deployment from 15 years to 10 years.

Energy Efficiency and Alternative Energy Programs (Exelon and PECO).

Energy Efficiency Programs. Pursuant to Act 129’s energy efficiency and conservation/demand (EE&C) reduction targets, PECO filed its EE&C plan with the PAPUC on July 1, 2009. The plan set forth how PECO will reduce electric consumption by at least 1% in its service territory by May 31, 2011 from expected consumption for the period June 1, 2009 through May 31, 2010 and by 3% by May 31, 2013. In accordance with Act 129, PECO also plans to reduce peak demand by a minimum of 4.5% of PECO’s annual system peak demand in the 100 hours of highest demand by May 31, 2013, measured against its peak demand during the period of June 1, 2007 through May 31, 2008. If PECO fails to achieve the required reductions in consumption within the stated deadlines, PECO will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of any EE&C plan may not exceed 2% of the electric company’s total annual revenue as of December 31, 2006. On October 28, 2009, the PAPUC issued an order providing partial approval of PECO’s EE&C plan. The approved plan totals more than $330 million and includes the CFL program, weatherization programs, an energy efficiency appliance rebate and trade-in program, rebates and energy efficiency programs for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. On December 24, 2009, PECO filed revisions to the portions of the plan not approved based on PAPUC feedback.

Alternative Energy Portfolio Standards. In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandated that beginning in 2007, or following the end of an electric distribution company’s retail electric generation rate cap transition period, certain percentages of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources (including solar or wind power, low-impact hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy generated within Pennsylvania and coal mine methane) ranges from 1.5% to 8.0% and the requirement for Tier II alternative energy resources (including waste coal, biomass energy generated outside of Pennsylvania, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing by-products of the pulping process and wood, distributed generation systems and integrated combined coal gasification technology) ranges from 4.2% to 10.0%. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129 in addition to those outlined in the AEPS Act. The AEPS Act mandates the 8.0% requirement for Tier I resources and the 10.0% requirement for Tier II resources must be met by the year ending May 31, 2021.

207

Combined Notes to Consolidated Financial Statements—(Continued)

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

The Pennsylvania Legislature is currently considering HB 80, which, if enacted into law, would increase the minimum required percentage of electric energy purchased and sold to retail electric customers from alternative energy resources and extend the period for such purchases and sales. HB 80 would increase the Tier 1 and solar purchase and sale requirements, limit eligible solar purchases to Pennsylvania generating sources and incorporate advanced coal combustion with limited carbon emissions as an acceptable alternative energy resource. Generation has proposed amendments to include extended nuclear uprates as a qualifying alternative energy source.

In 2007, the PAPUC approved PECO’s plan to acquire and bank approximately 450,000 non-solar Tier I AECs (corresponding to the expected annual output of approximately 240 MW of wind power) annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance following the completion of its electric generation rate cap transition period. The banked AECs may be used in either of the two consecutive AEPS reporting periods after PECO’s electric generation rate cap transition period. All costs incurred in connection with AEC procurement prior to 2011 are being deferred as a regulatory asset with a return on the unamortized balance and will be recovered from customers in 2011. Those costs, and PECO’s AEPS Act compliance costs incurred thereafter, will be recovered from customers on a full and current basis through a reconcilable ratemaking mechanism as contemplated by the AEPS Act. In conformance with the approved plan, PECO has entered into five-year agreements with accepted bidders, including Generation, totaling 452,000 AECs to be purchased annually.

On August 27, 2009, the PAPUC approved a settlement of PECO’s petition for early procurement and banking of up to 8,000 solar Tier 1 AECs annually for ten years. PECO’s procurement would employ the same surcharge cost-recovery mechanism that the PAPUC previously approved for non-solar Tier 1 AECs. The settlement provides for no cap on bid price, provides the PAPUC a 10 calendar day review period, permits facilities capable of generating a minimum of 300 AECs annually to bid and provides that no changes to the agreement with AEC suppliers will be accepted after PAPUC approval. On January 25, 2010, the PAPUC approved the fixed-price agreement solar AEC procurement results. PECO plans to enter into the fixed-price agreements by February 8, 2010.

PJM Transmission Rate Design (Exelon, ComEd and PECO). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd and PECO incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. In the short term, based on new transmission facilities approved by PJM, it is likely that allocating across PJM the costs of new facilities 500 kV and above will increase charges to ComEd and reduce charges to PECO, as compared to the allocation methodology in effect before the FERC order. After FERC ultimately denied all requests for rehearing on all issues, several parties filed petitions in the U.S. Court of Appeals for the Seventh Circuit for review of the decision. On August 6, 2009, the court issued its decision affirming FERC’s order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration its decision with regard to the costs of new facilities 500 kV and above. On September 21, 2009, two parties filed a petition for rehearing by the full court concerning the court’s decision to remand to FERC the part of the decision regarding the allocation of the costs of new

208

Combined Notes to Consolidated Financial Statements—(Continued)

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

facilities 500 kV and above. On October 20, 2009, the court denied the rehearing petition. On January 21, 2010, FERC issued an order establishing paper hearing procedures to supplement the record. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006 should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd’s results of operations, cash flows or financial position. PECO also has the right to file with the PAPUC for a change in retail rates to reflect changes in its wholesale transmission costs. PECO cannot predict the long-term impact of any rate design changes due to the uncertainty as to whether new facilities will be built and how the costs of new facilities less than 500 kV will be allocated; however, the impact may be material to its results of operations, cash flows, or financial position.

PJM-MISO Regional Rate Design (Exelon, ComEd and PECO). The current PJM-MISO Regional Rate Design is used to specify the pricing of transmission service between PJM and MISO and impacts ComEd and PECO due to purchases by suppliers from MISO. In August 2007, ComEd and PECO and several other transmission owners in PJM and MISO, as directed by a FERC order, filed with FERC to continue the existing transmission rate design between PJM and MISO. Additional transmission owners and certain other entities filed protests urging FERC to reject the filing. In September 2007, a complaint was filed asking FERC to find that the PJM-MISO rate design was unjust and unreasonable and to substitute a rate design that socializes the costs of all existing and new transmission facilities of 345 kV and above across PJM and MISO. In December 2008, FERC denied a request for rehearing of these orders and an appeal was filed in the United States Court of Appeals. On November 9, 2009, the court dismissed the appeal at the request of the appellant.

Authorized Return on Rate Base (Exelon, ComEd and PECO). In the September 2008 order in the 2007 Rate Case, the ICC authorized a return on ComEd’s distribution rate base using a weighted average debt and equity return of 8.36%, an increase over the 8.01% return previously authorized in the 2005 Rate Case. ComEd’s formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 9.43%, an increase over the 9.37% return previously authorized. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 57%. This equity cap is reduced to 56% in June 2010 and 55% in June 2011 and subsequent years. This transmission rate base return is updated annually in accordance with the formula-based rate calculation discussed above.

PECO’s transition period includes caps on electric generation rates that will expire on December 31, 2010 pursuant to the Competition Act. The electric distribution and transmission components of PECO’s rates continue to be regulated. PECO’s most recently approved weighted average debt and equity return on electric rate base, which included electric generation, was 11.23% (approved in 1990). PECO’s purchased gas cost rates are not subject to caps and do not earn a return. As part of the gas distribution rate case filed in March 2008, PECO requested that the PAPUC authorize it to establish base rates for natural gas distribution service using a weighted average debt and equity return on gas rate base of 8.90%. The joint settlement petition in that matter, approved in October 2008 by the PAPUC, did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. Prior to the 2008 gas distribution rate case, the most recently approved weighted average debt and equity return on gas rate base was 11.45% (approved in 1988).

209

Combined Notes to Consolidated Financial Statements—(Continued)

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

Market-Based Rates (Exelon, Generation, ComEd and PECO). Generation, ComEd and PECO are public utilities for purposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd and PECO have authority to execute wholesale electricity sales at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation, ComEd or PECO has 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 June 2007, FERC issued a Final Rule on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities (Order No. 697), which updated and modified the tests that FERC had implemented in 2004. That order was clarified in December 2007. Subsequently, Order No. 697 was largely affirmed and further clarified in Order No. 697-A, Order No. 697-B and Order No. 697-C. The Registrants do not expect that the Final Rule will have a material effect on their results of operations in the short-term. The longer-term impact will depend on the future application by FERC of Order Nos. 697 and future actions involving market-based rates.

During 2008, Generation, ComEd and PECO filed an analysis for generation in the Northeast region covering generation in PJM and ISO-New England and Generation filed an analysis for generation in the Southeast region covering generation in the Southern Company and Entergy areas; and in 2009, Generation filed an analysis for generation in the Central region covering generation in the MISO market. In each case, the filing used FERC’s updated screening tests, as required by the Final Rule. These analyses demonstrated that Exelon does not have market power in those areas and, therefore, is entitled to continue to sell at market-based rates in them. FERC accepted the 2008 filings on January 15, 2009 and September 2, 2009 and accepted the 2009 filing on October 26, 2009, affirming Exelon’s affiliates’ continued right to make sales at market-based rates.

Reliability Pricing Model (Exelon and Generation). On August 31, 2005, PJM submitted a proposal to FERC for a new capacity payment construct to replace PJM’s then-existing capacity obligation rules. The proposal provided for a forward capacity procurement auction to establish capacity and payment obligations using a demand curve and locational deliverability zones for capacity. The FERC affirmed PJM’s proposal for forward commitments and other matters, but encouraged PJM and the parties to that FERC proceeding to resolve other RPM issues by settlement. A settlement was reached on September 29, 2006 and was approved by FERC on December 22, 2006. The settlement provided for an auction 36 months in advance of each delivery year beginning with the delivery year ending May 31, 2012 and an expedited phase-in process for four transitional auctions covering delivery years ending on May 31 in 2008 through 2011. All but one appeal of FERC’s order approving RPM were withdrawn on February 27, 2009 and the remaining appeal was denied by the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) on March 17, 2009.

PJM’s four transitional RPM auctions took place in April 2007, July 2007, October 2007 and January 2008 and established prices for the period from June 1, 2007 through May 31, 2011. Subsequent auctions will take place 36 months ahead of the scheduled delivery year. The auction for the delivery year ending May 31, 2012 and May 31, 2013 occurred in May 2008 and May 2009, respectively. Thus far, the RPM capacity auctions have secured capacity for the PJM market through 2013. While auction results produced varying prices, as anticipated, the RPM has been beneficial for owners of generation facilities, particularly for such facilities located in constrained zones, as compared to the prior capacity-payment construct.

210

Combined Notes to Consolidated Financial Statements—(Continued)

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

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates and trade associations (referred to collectively as the RPM Buyers) filed a complaint at FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by FERC that established RPM. In the complaint, the RPM Buyers requested that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On September 19, 2008, FERC dismissed the complaint finding that no party violated PJM’s tariff and the prices determined during the initial auctions implementing the RPM were in accord with the tariff provisions governing the auctions. On June 18, 2009, FERC denied the RPM Buyers’ request for rehearing of FERC’s September 19, 2008 order. On August 14, 2009, RPM Buyers filed a petition with the U.S. Court of Appeals for the Fourth Circuit for review of the FERC’s September 19, 2008 order, rejecting their complaint that RPM resulted in unjust and unreasonable capacity prices. On September 17, 2009, PJM filed a motion to transfer the case to the D.C. Circuit on the grounds that the Fourth Circuit was an improper venue. On November 12, 2009, the court granted the motion. If the D.C. Circuit were to reverse FERC’s decision, FERC would be required to conduct additional proceedings regarding the substantive allegations in the complaint. Exelon and Generation believe that it is remote that the ultimate outcome of this matter will have a material adverse impact on their respective results of operations, cash flows or financial position.

In a companion order also issued on September 19, 2008, FERC directed PJM and its stakeholders to evaluate whether prospective changes should be made to RPM and, if a consensus is reached, file such a consensus with FERC in time to be in effect for the May 2009 RPM Auction. PJM filed a report with FERC on December 12, 2008 summarizing the discussions and explaining that a consensus was not reached. PJM also filed its own proposal with FERC on December 12, 2008. On March 26, 2009, FERC issued an order accepting in part and rejecting in part PJM’s December 12 filing, as amended by an Offer of Settlement filed by PJM and some members of PJM in response to the December 12 filing. A number of parties filed for rehearing and/or clarification of the March 26, 2009 Order. On August 14, 2009, the Commission granted in part and denied in part requests for rehearing and clarification. Any order may then be subject to review in the United States Court of Appeals.

License Renewals (Exelon and Generation). 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 application was challenged by a coalition of citizen groups (citizen groups) and the NJDEP, including filings made with the NRC’s ASLB, the NRC Commissioners and the U.S. Court of Appeals for the Third Circuit. These filings and appeals were rejected or denied. On April 8, 2009, the NRC issued the renewed operating license for Oyster Creek that expires in April 2029. On May 29, 2009, the citizen groups filed a Petition for Review of the NRC’s renewal of Oyster Creek’s operating license in the U.S. Court of Appeals for the Third Circuit. If the appeal is successful, it is unlikely that it would result in a revocation of the renewed license; however, it could cause the NRC to impose additional conditions over the course of the period of extended operation.

On January 8, 2008, AmerGen submitted an application to the NRC to extend the operating license of TMI Unit 1 for an additional 20 years. On October 22, 2009, the NRC issued the renewed operating license for TMI Unit 1 that expires in April 2034.

211

Combined Notes to Consolidated Financial Statements—(Continued)

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

On August 18, 2009, PSEG submitted an application to the NRC to extend the operating license of Salem Units 1 and 2 by 20 years. Exelon is part owner of the Salem Units. The NRC is expected to spend a total of 22 to 30 months to review the application before making a decision. The current operating licenses expire in 2016 and 2020, respectively.

3. Accounts Receivable (Exelon, Generation, ComEd and PECO)

Accounts receivable at December 31, 2009 and 2008 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows:


2009	Exelon			Generation			ComEd			PECO
Unbilled revenues	$	1,035		$	441		$	289		$	305
Allowance for uncollectible accounts		(225	)		(31	)		(77	)		(117	)

2008	Exelon			Generation			ComEd			PECO
Unbilled revenues	$	1,199		$	593		$	310		$	296
Allowance for uncollectible accounts		(238	)		(30	)		(57	)		(151	)

PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable, which PECO accounted for as a sale as of December 31, 2009. Under new guidance effective January 1, 2010, this agreement will be accounted for as a secured borrowing. See Note 1—Significant Accounting Policies for additional information. PECO retains the servicing responsibility for the sold receivables and has recorded a servicing liability. The agreement terminates on September 16, 2010, unless extended in accordance with its terms. As of December 31, 2009, PECO was in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and will seek alternate financing. See Note 7—Fair Value of Financial Assets and Liabilities for additional information regarding the servicing liability.

4. Property, Plant and Equipment (Exelon, Generation, ComEd and PECO)

Exelon

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2009 and 2008:


	Average Service Life (years)	2009		2008
Asset Category
Electric—transmission and distribution	5-75	$	19,441	$	18,509
Electric—generation	1-72		9,666		9,108
Gas—transportation and distribution	5-66		1,679		1,631
Common—electric and gas	5-50		517		496
Nuclear fuel ^(a)	1-8		3,340		2,811
Construction work in progress	N/A		1,263		1,038
Other property, plant and equipment ^(b)	5-58		458		462

Total property, plant and equipment			36,364		34,055
Less: accumulated depreciation ^(c)			9,023		8,242

Property, plant and equipment, net		$	27,341	$	25,813

212

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	Includes nuclear fuel that is in the fabrication and installation phase of $711 million and $490 million at December 31, 2009 and 2008, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $28 million and $31 million at December 31, 2009 and 2008, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $24 million and $22 million as of December 31, 2009 and 2008, respectively. Also includes unregulated property at ComEd and PECO.

(c)

Includes accumulated depreciation related to regulated property at ComEd and PECO of $4,565 million and $4,205 million as of December 31, 2009 and 2008, respectively. Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $1,383 million and $1,214 million as of December 31, 2009 and 2008, respectively. On December 2, 2009, Generation announced its intention to permanently retire four of its fossil-fired generating units effective May 31, 2011. Exelon recorded approximately $32 million of additional depreciation expense to reflect changes in useful lives for the plant assets that will be taken out of service prior to their previously estimated service period. See Note 14—Corporate Restructuring and Plant Retirements for additional information.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.


Average Service Life Percentage by Asset Category	2009		2008		2007
Electric—transmission and distribution	2.43	%	2.42	%	2.38	%
Electric—generation	2.28	%	2.02	%	1.90	%
Gas	1.75	%	1.74	%	1.69	%
Common—electric and gas	6.41	%	6.51	%	6.36	%

Generation

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2009 and 2008:


	Average Service Life (years)	2009		2008
Asset Category
Electric—generation	1-72	$	9,666	$	9,108
Nuclear fuel ^(a)	1-8		3,340		2,811
Construction work in progress	N/A		964		744
Other property, plant and equipment ^(b)	5-58		53		56

Total property, plant and equipment			14,023		12,719
Less: accumulated depreciation ^(c)			4,214		3,812

Property, plant and equipment, net		$	9,809	$	8,907

(a)	Includes nuclear fuel that is in the fabrication and installation phase of $711 million and $490 million at December 31, 2009 and 2008, respectively.

(b)

Includes buildings under capital lease with a net carrying value of $28 million and $31 million at December 31, 2009 and 2008, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $24 million and $22 million as of December 31, 2009 and 2008, respectively.

(c)

Includes accumulated amortization of nuclear fuel in the reactor core of $1,383 million and $1,214 million as of December 31, 2009 and 2008, respectively. On December 2, 2009, Generation announced its intention to permanently retire four of its fossil-fired generating units effective May 31, 2011. Generation recorded approximately $32 million of additional depreciation expense to reflect changes in useful lives for the plant assets that will be taken out of service prior to their previously estimated service period. See Note 14—Corporate Restructuring and Plant Retirements for additional information.

213

Combined Notes to Consolidated Financial Statements—(Continued)

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

The annual depreciation provisions as a percentage of average service life for electric generation assets were 2.28%, 2.02% and 1.90% for the years ended December 31, 2009, 2008 and 2007, respectively.

License Renewals. Generation’s depreciation provisions are based on the estimated useful lives of its generating stations, which assume 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 2—Regulatory Issues for additional information regarding license renewals.

Long-Lived Asset Impairments. Generation regularly evaluates the economic viability of its generating plants. During 2009, Generation assessed whether there had been any triggering events requiring an impairment assessment for any of its generating stations. Based on this analysis, it was determined that Generation did not have any triggering events requiring impairment assessments for any of its generating stations, except as noted below.

In connection with the decline in market conditions and the potential divestiture of the Texas plants (Handley, Mountain Creek and LaPorte generating stations) associated with the proposed merger with NRG that has since been terminated, Generation evaluated its Texas plants for potential impairment as of December 31, 2008. The impairment evaluation was performed to assess whether the carrying values of the plants were not recoverable. Generation’s evaluation indicated that the estimated undiscounted future cash flows exceeded the carrying values of the plants and an impairment did not exist as of December 31, 2008 under the held and used model.

Due to the continued decline in forward energy prices in the first quarter of 2009, Generation again evaluated its Texas plants for recoverability as of March 31, 2009. As the estimated undiscounted future cash flows and fair value of the Handley and Mountain Creek stations were less than the stations’ carrying values, the stations were determined to be impaired at March 31, 2009. LaPorte station was determined not to be impaired. Accordingly, the Handley and Mountain Creek stations were written down to fair value, and an impairment charge of $223 million was recorded in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations in the first quarter of 2009. The fair value of the stations was determined using the income (discounted cash flow), market (available comparables) and cost (replacement cost) valuation approaches.

ComEd

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2009 and 2008:


	Average Service Life (years)	2009		2008
Asset Category
Electric—transmission and distribution	5-75	$	14,031	$	13,335
Construction work in progress	N/A		178		140
Other property, plant and equipment ^(a)	50		45		46

Total property, plant and equipment			14,254		13,521
Less: accumulated depreciation ^(b)			2,129		1,866

Property, plant and equipment, net		$	12,125	$	11,655

214

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	Represents unregulated property.

(b)	Includes accumulated depreciation related to unregulated property of $4 million and $4 million as of December 31, 2009 and 2008, respectively.

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.57%, 2.53% and 2.49% for the years ended December 31, 2009, 2008 and 2007, respectively.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2009 and 2008:


	Average Service Life (years)	2009		2008
Asset Category
Electric—transmission and distribution	5-65	$	5,410	$	5,174
Gas—transportation and distribution	5-66		1,679		1,631
Common—electric and gas	5-50		517		496
Construction work in progress	N/A		117		103
Other property, plant and equipment ^(a)	45-50		16		15

Total property, plant and equipment			7,739		7,419
Less: accumulated depreciation ^(b)			2,442		2,345

Property, plant and equipment, net		$	5,297	$	5,074

(a)	Represents unregulated property.

(b)	Includes accumulated depreciation related to unregulated property of $2 million and $2 million as of December 31, 2009 and 2008, respectively.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.


Average Service Life Percentage by Asset Category	2009		2008		2007
Electric—transmission and distribution	1.97	%	2.03	%	2.03	%
Gas	1.75	%	1.74	%	1.69	%
Common—electric and gas	6.41	%	6.51	%	6.36	%

See Note 1—Significant Accounting Polices for further information regarding property, plant and equipment policies and accounting for capitalized software costs. See Note 9—Debt and Credit Agreements for further information regarding property, plant and equipment subject to mortgage liens.

215

Combined Notes to Consolidated Financial Statements—(Continued)

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

5. Jointly Owned Electric Utility Plant (Exelon, Generation and PECO)

Exelon’s, Generation’s and PECO’s undivided ownership interests in jointly owned electric plants at December 31, 2009 and 2008 were as follows:


	Nuclear generation									Fossil fuel generation									Transmission						Other
	Quad Cities			Peach Bottom			Salem ^(a)			Keystone			Conemaugh			Wyman			PA ^(b)			DE/NJ ^(c)			Other ^(d)
Operator		Generation			Generation			PSEG Nuclear			Reliant			Reliant			FP&L			First Energy			PSG&E
Ownership interest		75.00	%		50.00	%		42.59	%		20.99	%		20.72	%		5.89	%		22.00	%		42.55	%		44.24	%

Exelon’s share at December 31, 2009:
Plant	$	570		$	520		$	386		$	357		$	236		$	3		$	5		$	60		$	1
Accumulated depreciation		101			263			79			119			151			2			4			28			—
Construction work in progress		107			56			46			1			11			—			—			—			—

Exelon’s share at December 31, 2008:
Plant	$	512		$	490		$	379		$	192		$	233		$	2		$	5		$	60		$	1
Accumulated depreciation		85			256			73			114			148			1			4			27			—
Construction work in progress		60			21			37			107			2			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, 2009 and 2008.

(b)	PECO owns a 22.00% share in 127 miles of 500,000 voltage lines located in Pennsylvania.

(c)	PECO owns a 42.55% share in 131 miles of 500,000 voltage lines located in Delaware and New Jersey.

(d)	Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

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 fuel and operating and maintenance expenses on Exelon’s and Generation’s Consolidated Statements of Operations and in operating and maintenance expenses on PECO’s Consolidated Statements of Operations.

216

Combined Notes to Consolidated Financial Statements—(Continued)

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

6. Intangible Assets (Exelon, Generation, ComEd and PECO)

Goodwill

Exelon’s and ComEd’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2009 and 2008 were as follows:


	2009						2008
	Gross Amount ^(a)		Accumulated Impairment Losses		Carrying Amount		Gross Amount ^(a)		Accumulated Impairment Losses		Carrying Amount
Balance, January 1	$	4,608	$	1,983	$	2,625	$	4,608	$	1,983	$	2,625
Impairment losses		—		—		—		—		—		—

Balance, December 31,	$	4,608	$	1,983	$	2,625	$	4,608	$	1,983	$	2,625

(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

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 carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.

Exelon assesses goodwill impairment at its ComEd reporting unit. Accordingly, any goodwill impairment charge at ComEd will affect Exelon’s consolidated results of operations. As a result of new authoritative guidance for fair value measurement effective January 1, 2009, Exelon and ComEd now estimate the fair value of the ComEd reporting unit using a weighted combination of a discounted cash flow analysis and a market multiples analysis instead of the expected cash flow approach used in 2008 and prior years. The discounted cash flow analysis relies on a single scenario reflecting “base case” or “best estimate” projected cash flows for ComEd’s business and includes an estimate of ComEd’s terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include ComEd’s capital structure, discount and growth rates, utility sector market performance, operating and capital expenditure requirements, fair value of debt, the selection of peer group companies and recent transactions. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reporting units to Exelon’s enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multiple analysis.

2009 Annual Goodwill Impairment Assessment. The 2009 annual goodwill impairment assessment was performed as of November 1, 2009. The first step of the annual impairment analysis, comparing the fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill,

217

Combined Notes to Consolidated Financial Statements—(Continued)

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

therefore the second step was not required. Although financial markets have stabilized over the past year, current economic conditions continue to impact the market-related assumptions used in the 2009 annual assessment. While the estimated fair value of ComEd has increased since the 2008 assessment, deterioration of the market related factors used in the impairment review could possibly result in a future impairment loss of ComEd’s goodwill, which could be material.

2008 Annual Goodwill Impairment Assessment. The 2008 annual goodwill impairment assessment was performed as of November 1, 2008. The first step of the annual impairment analysis, comparing the fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill, therefore the second step was not required. The order in the 2007 Rate Case and the implementation of a formula-based transmission rate provided more certainty related to ComEd’s future cash flows. However, the economic downturn and the capital and credit market crisis affected the market-related assumptions resulting in a significant decrease in estimated fair value of ComEd since the 2007 assessment.

2007 Annual Goodwill Impairment Assessment. The 2007 annual goodwill impairment assessment was performed as of November 1, 2007. The first step of the annual impairment analysis, comparing the fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill, therefore the second step was not required.

Other Intangible Assets

Exelon’s and ComEd’s other intangible assets, included in deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2009:


	Gross		Accumulated Amortization			Net		Estimated amortization expense
	Gross		Accumulated Amortization			Net		2010		2011		2012		2013		2014
December 31, 2009
Chicago settlement—1999 agreement ^(a)	$	100	$	(61	)	$	39	$	3	$	3	$	3	$	3	$	3
Chicago settlement—2003 agreement ^(b)		62		(25	)		37		4		4		4		4		4

Total intangible assets	$	162	$	(86	)	$	76	$	7	$	7	$	7	$	7	$	7

(a)

In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments of $25 million to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.

(b)

In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third party on the City of Chicago’s behalf. Pursuant to the agreement discussed above, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under its 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in other long-term liabilities, are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.

For each of the years ended December 31, 2009, 2008 and 2007, Exelon’s and ComEd’s amortization expense related to intangible assets was $7 million.

218

Combined Notes to Consolidated Financial Statements—(Continued)

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

Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation and PECO). Exelon’s, Generation’s, and PECO’s other intangible assets, included in other deferred debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon and Generation) and AECs (PECO). As of December 31, 2009 and December 31, 2008, PECO had AECs of $13 million and $1 million, respectively. As of December 31, 2009 and December 31, 2008, the balances of RECs for Generation were $6 million and $2 million, respectively. See Note 2—Regulatory Issues for additional information on RECs and AECs.

7. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd and PECO)

Non-Derivative Financial Assets and Liabilities. As of December 31, 2009 and 2008, 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 Value of Financial Liabilities Recorded at the Carrying Amount

Exelon

The carrying amounts and fair values of Exelon’s long-term debt and SNF obligation as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	11,634	$	12,223	$	11,426	$	10,803
Long-term debt to PETT (including amounts due within one year)		415		426		1,124		1,193
Long-term debt to other financing trusts		390		325		390		200
Spent nuclear fuel obligation		1,017		832		1,015		544
Preferred securities of subsidiary		87		63		87		63

Fair values of long-term debt are determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. The fair value of preferred securities of subsidiaries is determined using observable market prices as these securities are actively traded. The carrying amount of Exelon’s and Generation’s SNF obligation resulted from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. Exelon’s and Generation’s obligation to the DOE accrues at the 13-week Treasury rate and fair value was determined by comparing the carrying amount of the obligation at the 13-week Treasury rate to the present value of the obligation discounted using the prevailing Treasury rate for a long-term obligation with an estimated maturity of 2020 (after being adjusted for Generation’s credit risk).

Generation

The carrying amounts and fair values of Generation’s long-term debt and SNF obligation as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,993	$	3,132	$	2,514	$	2,402
Spent nuclear fuel obligation		1,017		832		1,015		544

219

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	4,711	$	5,062	$	4,726	$	4,510
Long-term debt to financing trust		206		167		206		100

PECO

The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,221	$	2,346	$	1,971	$	1,954
Long-term debt to PETT (including amounts due within one year)		415		426		1,124		1,193
Long-term debt to other financing trusts		184		158		184		100
Preferred securities		87		63		87		63

Recurring Fair Value Measurements

To increase consistency and comparability in fair value measurements, the FASB established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1—quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities, exchange-based derivatives, mutual funds and money market funds.

•

Level 2—inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, non-exchange-based derivatives, commingled investment funds priced at NAV per fund share and fair value hedges.

•

Level 3—unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded non-exchange-based derivatives.

Upon Exelon’s and Generation’s initial adoption of the authoritative guidance for fair value measurements, and in periods since adoption, Exelon and Generation have classified investments in NDT commingled funds, reported at NAV, within Level 3 of the fair value hierarchy. The FASB issued authoritative guidance in September 2009, effective for periods ending after December 15, 2009, indicating that if a reporting entity has the ability to redeem its investment at NAV at the measurement

220

Combined Notes to Consolidated Financial Statements—(Continued)

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

date or at a future date, it shall be classified as Level 2 in the fair value hierarchy. As of December 31, 2009, Exelon and Generation continue to report these investments at NAV without adjustment and have classified them within Level 2 of the fair value hierarchy.

See Note 13—Retirement Benefits for further information regarding the fair value and related valuation techniques for pension and postretirement plan assets.

Exelon

The following table presents assets and liabilities measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and 2008:


As of December 31, 2009	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents^(a)	$	1,845		$	—		$	—		$	1,845
Nuclear decommissioning trust fund investments
Cash equivalents		2			120			—			122
Equity securities ^(b)		1,528			—			—			1,528
Commingled funds^(c)		—			2,086			—			2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		511			119			—			630
Debt securities issued by states of the United States and political subdivisions of the states		—			454			—			454
Corporate debt securities		—			710			—			710
Federal agency mortgage-backed securities		—			887			—			887
Commercial mortgage-backed securities (non-agency)		—			91			—			91
Residential mortgage-backed securities (non-agency)		—			9			—			9
Other debt obligations		—			76			—			76

Nuclear decommissioning trust fund investments subtotal ^(d)		2,041			4,552			—			6,593

Rabbi trust investments
Cash equivalents		28			—			—			28
Mutual funds^(e)(f)		13			—			—			13

Rabbi trust investments subtotal		41			—			—			41

Mark-to-market derivative net (liabilities) assets ^(g)(h)		(4	)		852			(44	)		804

Total assets		3,923			5,404			(44	)		9,283

Liabilities
Deferred compensation		—			(82	)		—			(82	)
Servicing liability		—			—			(2	)		(2	)

Total liabilities		—			(82	)		(2	)		(84	)

Total net assets (liabilities)	$	3,923		$	5,322		$	(46	)	$	9,199

221

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2008	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents^(a)	$	1,228	$	—		$	—		$	1,228
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—			13
Equity securities ^(b)		903		—			—			903
Commingled funds ^(c)		—		94			1,220			1,314
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		419		91			—			510
Debt securities issued by states of the United States and political subdivisions of the states		—		414			—			414
Corporate debt securities		—		764			—			764
Federal agency mortgage-backed securities		6		1,495			—			1,501
Commercial mortgage-backed securities (non-agency)		—		111			—			111
Other debt obligations		—		107			—			107

Nuclear decommissioning trust fund investments subtotal ^(d)		1,341		3,076			1,220			5,637

Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds ^(e)(f)		43		—			—			43

Rabbi trust investments subtotal		45		—			—			45

Mark-to-market derivative net assets ^(g)(h)(i)		12		806			106			924

Total assets		2,626		3,882			1,326			7,834

Liabilities
Deferred compensation		—		(85	)		—			(85	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(85	)		(2	)		(87	)

Total net assets	$	2,626	$	3,797		$	1,324		$	7,747

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Generation’s NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index.

(c)

Generation’s NDT funds own commingled funds that invest in both equity and fixed income securities. The commingled funds that invest in equity securities seek to track the performance of the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 3000 Index. The commingled funds that hold fixed income securities invest primarily in a diversified portfolio of high grade money market instruments and other short-term fixed income securities.

(d)	Excludes net assets of $76 million and net liabilities of $137 million consisting of payables related to pending securities purchases net of cash, interest receivables and receivables related to pending securities sales at December 31, 2009 and December 31, 2008, respectively.

(e)	The mutual funds held by the Rabbi trusts invest in large cap equity securities and municipal debt securities. During the second quarter of 2009, Exelon and ComEd recorded an other-than-temporary impairment of $7 million (pre-tax) related to Rabbi trust investments in other income and deductions.

(f)	Excludes $23 million and $19 million of the cash surrender value of life insurance investments at December 31, 2009 and December 31, 2008, respectively.

222

Combined Notes to Consolidated Financial Statements—(Continued)

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

(g)

Includes both current and noncurrent mark-to-market derivative assets and interest rate swaps, and is net of current and noncurrent mark-to-market derivative liabilities. In addition, the Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $302 million and $669 million at December 31, 2009 and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of Generation’s financial swap contract with ComEd, and a noncurrent asset of $2 million at December 31, 2009 related to the fair value of Generation’s block contracts with PECO, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(h)

Includes collateral postings received from and paid to counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $941 million and $3 million that are netted against Level 1, Level 2 and Level 3 mark-to-market derivative net assets, respectively, as of December 31, 2009. Collateral received from counterparties, net of collateral paid to counterparties, totaled $11 million, $741 million and $1 million that are netted against Level 1, Level 2 and Level 3 mark-to-market derivative net assets, respectively, as of December 31, 2008.

(i)

Exelon and Generation reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with the current year presentation. Refer to Note 8-Derivative Financial Instruments for further discussion. The impact of the reclassification was an increase of $245 million to Level 2 mark-to-market derivative net assets.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


For the Year Ended December 31, 2009	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2009	$	1,220		$	106		$	(2	)	$	1,324
Total realized / unrealized gains (losses)
Included in income		119			(134	)^(a)		—			(15	)
Included in other comprehensive income		—			5	^(b)		—			5
Included in regulatory assets/liabilities		275			(2	)		—			273
Change in collateral		—			(2	)					(2	)
Purchases, sales and issuances, net		337			—			—			337
Transfers out of Level 3		(1,951	)^(c)		(17	)		—			(1,968	)

Balance as of December 31, 2009	$	—		$	(44	)	$	(2	)	$	(46	)

The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2009	$	—		$	(79	)	$	—		$	(79	)

(a)	Includes the reclassification of $55 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)

Excludes $782 million of changes in the fair value and $267 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd, and $2 million of changes in the fair value of Generation’s block contracts with PECO. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	As of December 31, 2009, investments in NDT commingled funds, stated at NAV, were transferred out of Level 3 and into Level 2 in accordance with FASB issued authoritative guidance noted above.

223

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2008	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2008	$	2,019		$	52		$	(1	)	$	2,070
Total realized / unrealized (losses) gains
Included in income		(321	)		35	^(a)		(1	)		(287	)
Included in other comprehensive income		—			(32	)^(b)		—			(32	)
Included in regulatory liabilities		(553	)		—			—			(553	)
Change in collateral		—			(1	)		—			(1	)
Purchases, sales and issuances, net		109			—			—			109
Transfers into (out of ) Level 3		(34	)		52			—			18

Balance as of December 31, 2008	$	1,220		$	106		$	(2	)	$	1,324

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2008	$	(310	)	$	125		$	—		$	(185	)

(a)	Includes the reclassification of $90 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $888 million of changes in the fair value and $24 million of realized gains due to settlements associated with Generation’s financial swap contract with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

The following table presents total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


	Operating Revenue			Purchased Power			Fuel			Other, net
Total (losses) gains included in income for the year ended December 31, 2009	$	(86	)	$	(11	)	$	(37	)	$	119
Change in the unrealized losses relating to assets and liabilities held as of the year ended December 31, 2009	$	(2	)	$	(8	)	$	(69	)	$	—


	Operating Revenue		Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the year ended December 31, 2008	$	63	$	(12	)	$	(16	)	$	(321	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of the year ended December 31, 2008	$	107	$	(34	)	$	52		$	(310	)

224

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation

The following table presents assets and liabilities measured and recorded at fair value on Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and December 31, 2008:


As of December 31, 2009	Level 1			Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	1,040		$	—		$	—	$	1,040
Nuclear decommissioning trust fund investments
Cash equivalents		2			120			—		122
Equity securities ^(b)		1,528			—			—		1,528
Commingled funds^(c)		—			2,086			—		2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		511			119			—		630
Debt securities issued by states of the United States and political subdivisions of the states		—			454			—		454
Corporate debt securities		—			710			—		710
Federal agency mortgage-backed securities		—			887			—		887
Commercial mortgage-backed securities (non-agency)		—			91			—		91
Residential mortgage-backed securities (non-agency)		—			9			—		9
Other debt obligations		—			76			—		76

Nuclear decommissioning trust fund investments subtotal ^(d)		2,041			4,552			—		6,593

Rabbi trust investments ^(e)(f)		4			—			—		4
Mark-to-market derivative net (liabilities) assets^(g)(h)		(4	)		842			931		1,769

Total assets		3,081			5,394			931		9,406

Liabilities
Deferred compensation		—			(23	)		—		(23	)

Total liabilities		—			(23	)		—		(23	)

Total net assets	$	3,081		$	5,371		$	931	$	9,383

225

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2008	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	1,103	$	—		$	—	$	1,103
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—		13
Equity securities ^(b)		903		—			—		903
Commingled funds^(c)		—		94			1,220		1,314
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		419		91			—		510
Debt securities issued by states of the United States and political subdivisions of the states		—		414			—		414
Corporate debt securities		—		764			—		764
Federal agency mortgage-backed securities		6		1,495			—		1,501
Commercial mortgage-backed securities (non-agency)		—		111			—		111
Other debt obligations		—		107			—		107

Nuclear decommissioning trust fund investments subtotal ^(d)		1,341		3,076			1,220		5,637

Rabbi trust investments^(e)(f)		—		4			—		4
Mark-to-market derivative net assets^(g)(h)(i)		12		789			562		1,363

Total assets		2,456		3,869			1,782		8,107

Liabilities
Deferred compensation		—		(25	)		—		(25	)

Total liabilities		—		(25	)		—		(25	)

Total net assets	$	2,456	$	3,844		$	1,782	$	8,082

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Generation’s NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International EAFE Index.

(c)

Generation’s NDT funds own commingled funds that invest in both equity and fixed income securities. The commingled funds that invest in equity securities seek to match the performance of the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 3000 Index. The commingled funds that hold fixed income securities invest primarily in a diversified portfolio of high grade money market instruments and other short-term fixed income securities.

(d)

Excludes net assets of $76 million and net liabilities of $137 million at December 31, 2009 and December 31, 2008, respectively. These items consist of payables related to pending securities purchases net of cash, interest and dividend receivables and receivables related to pending securities sales.

(e)	The mutual funds held by the Rabbi trusts that are invested in common stock of S&P 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(f)	Excludes $7 million and $6 million of the cash surrender value of life insurance investments at December 31, 2009 and December 31, 2008, respectively.

(g)

Includes both current and noncurrent mark-to-market derivative assets, and is net of current and noncurrent mark-to-market derivative liabilities. In addition, the Level 3 balance includes current and noncurrent assets for Generation of $302 million and $669 million at December 31, 2009 and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of Generation’s financial swap contract with ComEd, and a noncurrent asset of $2 million at December 31, 2009 related to the fair value of Generation’s block contracts with PECO. All of the mark-to-market balances Generation carries associated with the financial swap contract with ComEd and the block contracts with PECO eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(h)

226

Combined Notes to Consolidated Financial Statements—(Continued)

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

(i)

Exelon and Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with the current year presentation. Refer to Note 8-Derivative Financial Instruments for further discussion. The impact of the reclassification was an increase of $245 million to Level 2 mark-to-market derivative net assets.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


Year Ended December 31, 2009	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Total
Balance as of January 1, 2009	$	1,220		$	562		$	1,782
Total unrealized / realized gains (losses)
Included in income		119			(134	)^(a)		(15	)
Included in other comprehensive income		—			522	^(b)		522
Included in noncurrent payables to affiliates		275			—			275
Change in Collateral		—			(2	)		(2	)
Purchases, sales, issuances and settlements, net		337			—			337
Transfers out of Level 3		(1,951	)^(c)		(17	)		(1,968	)

Balance as of December 31, 2009	$	—		$	931		$	931

The amount of total gains losses included in income attributed to the change in unrealized losses related to assets and liabilities held as of December 31, 2009	$	—		$	(79	)	$	(79	)

(a)	Includes the reclassification of $55 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)

Includes $782 million of changes in the fair value and $267 million of realized losses due to settlements associated with Generation’s financial swap with ComEd. Also includes $2 million of changes in the fair value of Generation’s block contracts with PECO. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	As of December 31, 2009, investments in NDT commingled funds, stated at NAV, were transferred out of Level 3 and into Level 2, in accordance with FASB issued authoritative guidance noted above.


Year Ended December 31, 2008	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Total
Balance as of January 1, 2008	$	2,019		$	(403	)	$	1,616
Total unrealized / realized (losses) gains
Included in income		(321	)		35	^(a)		(286	)
Included in other comprehensive income		—			879	^(b)		879
Included in noncurrent payables to affiliates		(553	)		—			(553	)
Change in Collateral		—			(1	)		(1	)
Purchases, sales, issuances and settlements, net		109			—			109
Transfers into or (out of) Level 3		(34	)		52			18

Balance as of December 31, 2008	$	1,220		$	562		$	1,782

The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2008	$	(310	)	$	125		$	(185	)

227

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	Includes the reclassification of $90 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $888 million of changes in the fair value and $24 million of realized gains due to settlements associated with Generation’s financial swap with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


	Operating Revenue			Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the year ended December 31, 2009	$	(86	)	$	(11	)	$	(37	)	$	119
Change in the unrealized losses relating to assets and liabilities held as of the year ended December 31, 2009	$	(2	)	$	(8	)	$	(69	)	$	—


	Operating Revenue		Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the year ended December 31, 2008	$	63	$	(12	)	$	(16	)	$	(321	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of the year ended December 31, 2008	$	107	$	(34	)	$	52		$	(310	)

ComEd

The following table presents assets measured and recorded at fair value on ComEd’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and 2008:


As of December 31, 2009	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	25	$	—		$	—		$	25
Rabbi trust investments^(b)
Cash equivalents		28		—			—			28

Total assets		53		—			—			53

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)
Mark-to-market derivative liabilities ^(c)		—		—			(971	)		(971	)

Total liabilities		—		(8	)		(971	)		(979	)

Total net assets (liabilities)	$	53	$	(8	)	$	(971	)	$	(926	)

228

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2008	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	16	$	—		$	—		$	16
Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds^(d)		32		—			—			32
Rabbi trust investment subtotal		34		—			—			34

Total assets		50		—			—			50

Liabilities
Deferred compensation obligation		—		(7	)		—			(7	)
Mark-to-market derivative liabilities ^(c)		—		—			(456	)		(456	)

Total liabilities		—		(7	)		(456	)		(463	)

Total net assets (liabilities)	$	50	$	(7	)	$	(456	)	$	(413	)

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	During the second quarter of 2009, ComEd recorded an other-than-temporary impairment of $7 million (pre-tax) related to Rabbi trust investments in other income and deductions.

(c)

The Level 3 balance is comprised of the current and noncurrent liability of $302 million and $669 million at December 31, 2009, respectively, and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of ComEd’s financial swap contract with Generation which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(d)	The mutual funds held by the Rabbi trusts invest in stocks in the Russell 1000 index and municipal securities that are primarily rated as investment grade.

The following tables present the fair value reconciliation of Level 3 assets measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


For the Year Ended December 31, 2009	Mark-to-Market Derivatives
Balance as of January 1, 2009	$	(456	)
Total realized / unrealized gains (losses) included in regulatory assets ^(a)		(515	)

Balance as of December 31, 2009	$	(971	)

(a)	Includes $782 million of changes in the fair value and $267 million of realized gains due to settlements associated with ComEd’s financial swap with Generation. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


For the Year Ended December 31, 2008	Mark-to-Market Derivatives
Balance as of January 1, 2008	$	456
Total realized / unrealized losses included in regulatory assets ^(a)		(912	)

Balance as of December 31, 2008	$	(456	)

(a)	Includes $888 million of changes in the fair value and $24 million of realized losses due to settlements associated with ComEd’s financial swap with Generation. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

229

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO

The following table presents assets and liabilities measured and recorded at fair value on PECO’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and 2008:


December 31, 2009	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	281	$	—		$	—		$	281
Rabbi trust investments—mutual funds ^(b)(c)		7		—			—			7

Total assets		288		—			—			288

Liabilities
Deferred compensation obligation		—		(25	)		—			(25	)
Mark-to-market derivative liabilities ^(d)		—		—			(4	)		(4	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(25	)		(6	)		(31	)

Total net assets (liabilities)	$	288	$	(25	)	$	(6	)	$	257


As of December 31, 2008	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	26	$	—		$	—		$	26
Rabbi trust investments—mutual funds ^(b)(c)		6		—			—			6

Total assets		32		—			—			32

Liabilities
Deferred compensation obligation		—		(28	)		—			(28	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(28	)		(2	)		(30	)

Total net assets (liabilities)	$	32	$	(28	)	$	(2	)	$	2

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	The mutual funds held by the Rabbi Trust invest in the common stock of S&P 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(c)	Excludes $12 million and $10 million of the cash surrender value of life insurance investments at December 31, 2009 and December 31, 2008, respectively.

(d)

The Level 3 balance represents a noncurrent liability of $4 million at December 31, 2009 related to the fair value of PECO’s block contracts, which includes a $2 million noncurrent liability related to the fair value of PECO’s block contracts with Generation that eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

230

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents the fair value reconciliation of Level 3 assets measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


For the Year Ended December 31, 2009	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2009	$	—		$	(2	)	$	(2	)
Total unrealized losses included in regulatory assets		(4	)		—			(4	)

Balance as of December 31, 2009	$	(4	)	$	(2	)	$	(6	)


For the Year Ended December 31, 2008	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2008	$	—		$	(1	)	$	(1	)
Total unrealized losses included in net income		—			(1	)		(1	)

Balance as of December 31, 2008	$	—		$	(2	)	$	(2	)

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

Cash Equivalents (Exelon, Generation, ComEd and PECO). The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation). The trust fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation’s investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies restrict the trust funds from holding alternative investments and limit the trust funds’ exposures to investments in highly illiquid markets. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities, are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ—Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices and price types are obtained from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security.

231

Combined Notes to Consolidated Financial Statements—(Continued)

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

The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. To draw parallels from the trading and quoting of fixed income securities with similar features, pricing services consider various characteristics including the issuer, maturity, purpose of loan, collateral attributes, prepayment speeds, interest rates and credit ratings in order to properly value these securities.

Commingled funds, which are similar to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of short-term commingled funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable on the 15th of the month and the last business day of the month, however, the fund manager may designate any day as a valuation date for the purpose of purchasing or redeeming units. Commingled funds are categorized in Level 2 at December 31, 2009 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets of the underlying equity securities and because they are offered to a limited group of investors and, therefore, not traded in an active market. See Note 11—Asset Retirement Obligations for further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, ComEd and PECO). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants’ Consolidated Balance Sheets. The fair values of the shares of the funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

The Registrants evaluate the securities held in their Rabbi trusts for other-than-temporary impairment by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. During June 2009, ComEd concluded that certain investments were other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the securities and considerations of ComEd’s ability and intent to hold the investments until the recovery of their cost basis. This analysis resulted in an impairment charge of $7 million (pre-tax) recorded in other income and deductions associated with ComEd’s investments held in Rabbi trusts.

Mark-to-Market Derivatives (Exelon, Generation, ComEd and PECO). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based derivatives are valued using indicative price quotations

232

Combined Notes to Consolidated Financial Statements—(Continued)

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

available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of non-exchange-based derivative contracts is valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For non-exchange-based derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ non-exchange-based derivatives are predominately at liquid trading points. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in their assessment of credit and nonperformance risk. The impacts of credit and nonperformance risk were not material to the financial statements.

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. Exelon uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, counterparty credit risk and market parameters such as interest rates and volatility. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 8—Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd and PECO). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized in Level 2 in the fair value hierarchy.

Servicing Liability (Exelon and PECO). PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable. A servicing liability was recorded for the agreement in accordance with the current

233

Combined Notes to Consolidated Financial Statements—(Continued)

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

authoritative guidance for servicing of assets and extinguishment of liabilities. The servicing liability is included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets. The fair value of the liability has been determined using internal estimates based on provisions in the agreement, which are categorized as Level 3 inputs in the fair value hierarchy. See Note 18—Commitments and Contingencies for further discussion on the accounts receivable agreement.

Non-recurring Fair Value Measurements

Asset Impairment (Exelon and Generation)

As discussed in Note 4—Property, Plant and Equipment, as of March 31, 2009, Generation tested its Texas plants for potential impairment and recognized an impairment charge of $223 million in the first quarter of 2009 to reduce the carrying value of the Handley and Mountain Creek stations to fair value.

The impairment charge recorded by Generation for the Handley and Mountain Creek stations incorporated the fair values of the plants using unobservable inputs falling within Level 3 of the fair value hierarchy. Generation determined fair value considering multiple valuation techniques including the income (discounted cash flow), market (available comparables) and cost (replacement cost) valuation approaches. The results were evaluated and weighted, considering the reasonableness of the range indicated by those results. Significant inputs used under the income approach included forecasted cash flows based on forecasted generation, forward prices of natural gas and electricity, overall generation availability ERCOT and discount rate assumptions. Significant inputs under the transaction approach included market multiples that were derived from comparable transactions for peaking plants in ERCOT and other market regions and discount rate assumptions.

8. Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical contracts as well as financial derivative contracts including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt, commercial paper and lines of credit.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value. Under these provisions, economic hedges are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and normal sales scope exception. The Registrants have applied the normal purchases and normal sales scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. For economic hedges that qualify and are designated as cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. For economic hedges that do not qualify or are not designated as cash flow hedges, changes in the fair value of the derivative are recognized in earnings each period and are classified as other derivatives in the following tables. Non-derivative contracts for access to additional

234

Combined Notes to Consolidated Financial Statements—(Continued)

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

generation and for sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 18 – Commitments and Contingencies. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

Commodity Price Risk (Exelon, Generation, ComEd and PECO)

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over three-year periods. As of December 31, 2009, the percentage of expected generation hedged was 91%—94%, 69%—72 %, and 37%—40 % for 2010, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.

ComEd has locked in a fixed price for a significant portion of its commodity price risk through the five-year financial swap contract with Generation that expires on May 31, 2013, which is discussed in more detail below. In addition, the contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement agreements, which are further discussed in Note 2—Regulatory Issues, qualify for the normal purchases and normal sales scope exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd’s price risk related to power procurement is limited.

In order to fulfill a requirement of the Illinois Settlement, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to hedge spot market purchases, which along with ComEd’s remaining energy procurement contracts, meet its

235

Combined Notes to Consolidated Financial Statements—(Continued)

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

load service requirements. The remaining swap contract volumes are 2,000 MW for the period extending June 2009 through May 2010 and 3,000 MW from June 2010 through May 2013. The terms of the financial swap contract require Generation to pay the market price for a portion of ComEd’s electricity supply requirement, while ComEd pays a fixed price. The contract is to be settled net, for the difference between the fixed and market pricing, and the financial terms only cover energy costs and do not cover capacity or ancillary services. The financial swap contract is a derivative financial instrument that has been designated by Generation as a cash flow hedge. Consequently, Generation records the fair value of the swap on its balance sheet and records changes in fair value to OCI. ComEd has not elected hedge accounting for this derivative financial instrument and records the fair value of the swap on its balance sheet. However, since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 2—Regulatory Issues for additional information regarding the Illinois Settlement. In Exelon’s consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated.

PECO has transferred substantially all of its commodity price risk related to its procurement of electric supply to Generation through a PPA that expires December 31, 2010. The PPA is not considered a derivative under current derivative authoritative guidance.

As part of the preparation for the expiration of the PPA, PECO has entered into derivative contracts to procure electric supply through a competitive RFP process as outlined in its PAPUC-approved DSP Program, which is further discussed in Note 2—Regulatory Issues. Based on Pennsylvania legislation and the DSP Program permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement will be limited. PECO will lock in fixed prices for a significant portion of its commodity price risk following the expiration of the electric generation rate caps through full requirements contracts and block contracts. PECO’s full requirements fixed price contracts qualify for the normal purchases and normal sales scope exception. PECO accounts for the block contracts as other derivatives, which are recorded on its balance sheet at fair value and the change in fair value each period is recorded as a regulatory asset or liability.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy deliverability requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and management agreements that are derivatives qualify for the normal purchases and normal sales exception. Additionally, in accordance with the 2009 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2009 PGC settlement, PECO is required to lock in (i.e. economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program covers 22% to 29% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price

236

Combined Notes to Consolidated Financial Statements—(Continued)

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

changes as opposed to hedging an exposure and is subject to limits established by Exelon’s RMC. The proprietary trading activities which included volumes of 7,578 GWh, 8,891 GWh and 20,323 GWh for years ended December 31, 2009, 2008 and 2007, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. Neither ComEd nor PECO enter into derivatives for proprietary trading purposes.

Interest Rate Risk (Exelon, Generation and ComEd)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to achieve a lower cost of capital. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in Exelon’s, Generation’s, and ComEd’s pre-tax income for the year ended December 31, 2009.

Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows for the year ended December 31, 2009:


Income Statement Classification	Loss on Swaps			Gain on Borrowings
Interest expense	$	(7	)	$	7

At December 31, 2009 and 2008, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $10 million and $17 million, respectively. During the years ended December 31, 2009 and 2008, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

Cash Flow Hedges. At December 31, 2009 and 2008, the Registrants did not have any interest rate swaps designated as cash flow hedges outstanding. In connection with Generation’s September 2009 $1.5 billion debt issuance, Generation entered into forward-starting interest rate swaps in the aggregate notional amount of $1.1 billion. The interest rate swaps were settled on September 16, 2009 with Generation recording a $7 million pre-tax gain. The gain was recorded to OCI within Generation’s Consolidated Balance Sheets and will be amortized to income over the life of the related debt as a reduction in interest expense.

Fair Value Measurement (Exelon, Generation, ComEd and PECO)

Fair value accounting guidance requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty, as well as netting of collateral, is aggregated in the collateral and netting column. Excluded from the tables below are economic hedges that qualify for the normal purchases and normal sales exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

237

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, ComEd and PECO as of December 31, 2009:


	Generation															ComEd			PECO			Other					Exelon
Derivatives	Cash Flow Hedges ^(a,d)			Other Derivatives			Proprietary Trading			Collateral and Netting ^(b)			Subtotal^(c)			IL Settlement Swap ^(a)			Other Derivatives ^(d)			Other Derivatives		Inter- company Eliminations ^(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	576		$	913		$	193		$	(1,306	)	$	376		$	—		$	—		$	—	$	—		$	376
Mark-to-market derivative assets with affiliate (current assets)		302			—			—			—			302			—			—			—		(302	)		—
Mark-to-market derivative assets (noncurrent assets)		423			792			102			(678	)		639			—			—			10		—			649
Mark-to-market derivative assets with affiliate (noncurrent assets)		671			—			—			—			671			—			—			—		(671	)		—

Total mark-to-market derivative assets	$	1,972		$	1,705		$	295		$	(1,984	)	$	1,988		$	—		$	—		$	10	$	(973	)	$	1,025

Mark-to-market derivative liabilities (current liabilities)	$	(18	)	$	(743	)	$	(172)		$	735		$	(198)		$	—			—		$	—	$	—		$	(198)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(302	)		—			—		302			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(42	)		(183	)		(98	)		302			(21	)		—			(2	)		—		—			(23	)
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)		—			—			—			—			—			(669	)		(2	)		—		671			—

Total mark-to-market derivative liabilities		(60	)		(926	)		(270	)		1,037			(219	)		(971	)		(4	)		—		973			(221	)

Total mark-to-market derivative net assets (liabilities)	$	1,912		$	779		$	25		$	(947	)	$	1,769		$	(971	)	$	(4	)	$	10	$	—		$	804

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $302 million and $669 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract, as described above.

238

Combined Notes to Consolidated Financial Statements—(Continued)

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

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c)

Current and noncurrent assets are shown net of collateral of $502 million and $376 million, respectively, and current liabilities are shown inclusive of collateral of $69 million, respectively. The allocation of collateral had no impact to noncurrent liabilities. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $947 million at December 31, 2009.

(d)	Includes a noncurrent liability for PECO and a noncurrent asset for Generation of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2009.

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of December 31, 2008:


	Generation															ComEd			Other					Exelon
Derivatives	Cash Flow Hedges^(a)(d)			Other Derivatives ^(d)			Proprietary Trading ^(d)			Collateral and Netting^(b)(d)			Subtotal ^(c)(d)			IL Settlement Swap ^(a)			Other Derivatives		Inter- company Eliminations ^(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	610		$	1,295		$	376		$	(1,801	)	$	480		$	—		$	—	$	—		$	480
Mark-to-market derivative assets with affiliate (current assets)		111			—			—			—			111			—			—		(111	)		—
Mark-to-market derivative assets (noncurrent assets)		438			752			123			(651	)		662			—			17		—			679
Mark-to-market derivative assets with affiliate (noncurrent assets)		345			—			—			—			345			—			—		(345	)		—

Total mark-to-market derivative assets	$	1,504		$	2,047		$	499		$	(2,452	)	$	1,598		$	—		$	17	$	(456	)	$	1,159

Mark-to-market derivative liabilities (current liabilities)	$	(47	)	$	(1,253	)	$	(291	)	$	1,379		$	(212	)	$	—		$	—	$	—		$	(212	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(111	)		—		111			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(20	)		(223	)		(100	)		320			(23	)		—			—		—			(23	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(345	)		—		345			—

Total mark-to-market derivative liabilities		(67	)		(1,476	)		(391	)		1,699			(235	)		(456	)		—		456			(235	)

Total mark-to-market derivative net assets (liabilities)	$	1,437		$	571		$	108		$	(753	)	$	1,363		$	(456	)	$	17	$	—		$	924

(a)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $111 million and $345 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract, as described above. At Exelon, the fair value balances are eliminated upon consolidation.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

239

Combined Notes to Consolidated Financial Statements—(Continued)

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

(c)

Current and noncurrent assets are shown net of collateral of $355 million and $333 million, respectively and current liabilities are shown inclusive of collateral of $65 million, respectively. The allocation of collateral had no impact to noncurrent liabilities. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $753 million at December 31, 2008.

(d)	Exelon and Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with current year presentation, as discussed within this footnote.

Cash Flow Hedges (Exelon and Generation). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At December 31, 2009, Generation had net unrealized pre-tax gains on effective cash flow hedges of $1,912 million being deferred within accumulated OCI, including approximately $971 million related to the financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at December 31, 2009, approximately $860 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $302 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges will occur during 2010 through 2012, and the ComEd financial swap contract during 2010 through 2013.

Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. For the year ended December 31, 2009, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.

The table below provides the activity of accumulated OCI related to cash flow hedges for the year ended December 31, 2009 and 2008, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.


	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation		Exelon
		Energy Related Hedges		Total Cash Flow Hedges
Accumulated OCI derivative gain (loss) at January 1, 2008		$(548	)^(a)	$	(292	)
Effective portion of changes in fair value		1,101	^(b)		567
Reclassifications from accumulated OCI to net income	Operating Revenue	328	^(c)		314
Ineffective portion recognized in income	Purchased Power	(26	)		(26	)
Accumulated OCI derivative gain at December 31, 2008		$855	^(a)	$	563
Effective portion of changes in fair value		1,227	^(b)		757
Reclassifications from accumulated OCI to net income	Operating Revenue	(939	)^(c)		(778	)
Ineffective portion recognized in income	Purchased Power	9			9

Accumulated OCI derivative gain (loss) at December 31, 2009		$1,152	^(a)(d)	$	551

240

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)

Includes $585 million gain, $275 million gain and $275 million loss, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2009, 2008 and 2007, respectively, and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of December 31, 2009.

(b)

Includes $471 million and $535 million of gains, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2009 and 2008, respectively, and $1 million of gain, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the year ended December 31, 2009.

(c)	Includes $161 million loss and $15 million gain, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2009 and 2008, respectively.

(d)	Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2009. See Note 9 – Debt and Credit Agreements for further information.

During the years ended December 31, 2009, 2008 and 2007, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $1,559 million pre-tax gain, a $544 million pre-tax loss and a $15 million pre-tax gain, respectively. Given that the cash flow hedges primarily consist of forward power sales and power swaps and do not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges is primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were $15 million, $44 million and $29 million for the years ended December 31, 2009, 2008, and 2007, respectively. At December 31, 2008 cash flow hedge ineffectiveness resulted in an adjustment of $15 million to accumulated OCI on the balance sheet in order to reflect the effective portion of derivative gains or losses. At December 31, 2009, cash flow hedge ineffectiveness was not significant.

Exelon’s energy related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $1,292 million pre-tax gain, $521 million pre-tax loss and $10 million pre-tax gain for the years ended December 31, 2009, 2008 and 2007, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were $15 million, $44 million and $29 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Other Derivatives (Exelon and Generation). Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the years ended December 31, 2009, 2008 and 2007, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and are included in net fair value changes related to derivatives in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

241

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Exelon and Generation
For the Year Ended December 31, 2009	Purchased Power			Fuel			Total
Change in fair value	$	206		$	(72	)	$	134
Reclassification to realized at settlement		(97	)		159			62

Net mark-to-market gains (losses)	$	109		$	87		$	196


	Exelon and Generation
For the Year Ended December 31, 2008	Purchased Power			Fuel			Total
Change in fair value	$	315		$	180		$	495
Reclassification to realized at settlement		55			(143	)		(88	)

Net mark-to-market gains (losses)	$	370		$	37		$	407


	Exelon and Generation
For the Year Ended December 31, 2007 ^(a)	Purchased Power			Fuel			Total
Change in fair value	$	(6	)	$	(37	)	$	(43	)
Reclassification to realized at settlement		(218	)		118			(100	)

Net mark-to-market gains (losses)	$	(224	)	$	81		$	(143	)

(a)	Table excludes $4 million related to ComEd included within revenue and $27 million related to other included within fuel expense.

Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2009, 2008 and 2007, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts entered into for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in Net fair value changes related to derivatives in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


	Location on Income Statement	For the Year Ended December 31,
	Location on Income Statement	2009			2008			2007
Change in fair value	Operating Revenue	$	3		$	106		$	42
Reclassification to realized at settlement	Operating Revenue		(86	)		(43	)		(8	)

Net mark-to-market gains (losses)	Operating Revenue	$	(83	)	$	63		$	34

242

Combined Notes to Consolidated Financial Statements—(Continued)

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

Credit Risk (Exelon, Generation, ComEd and PECO)

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 derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters 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 allow for cross-product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative 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 margining 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.

The following tables provide information on Generation’s credit exposure for all derivative instruments, which includes contracts that qualify for the normal purchases and normal sales exception, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2009. 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 credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs and NYMEX and ICE commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $123 million and $174 million, respectively. See Note 21—Related-Party Transactions for further information.


Rating as of December 31, 2009	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	$	1,183	$	464	$	719	1	$	76
Non-investment grade		15		5		10	—		—
No external ratings
Internally rated—investment grade		34		5		29	—		—
Internally rated—non-investment grade		1		1		—	—		—

Total	$	1,233	$	475	$	758	1	$	76

243

Combined Notes to Consolidated Financial Statements—(Continued)

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


Net Credit Exposure by Type of Counterparty	December 31, 2009
Financial institutions	$	259
Investor-owned utilities, marketers and power producers		431
Other		68

Total	$	758

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on the price of energy in the spot market compared to the benchmark prices. The benchmark prices are the future prices of energy projected through the contract term and are set at the point of contract execution. If the price of energy in the spot market exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2009, ComEd’s net credit exposure to energy suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2—Regulatory Issues for further information.

PECO has a PPA with Generation under which Generation has agreed to supply PECO with all of PECO’s electric supply needs through 2010 at prices that are below current market prices. The price for this electricity is essentially equal to the energy revenues earned from customers. PECO could be negatively affected if Generation could not perform under the PPA.

PECO’s supplier master agreements that govern the terms of its DSP program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from S&P, Fitch or Moody’s and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2009, PECO had no net credit exposure to energy suppliers.

PECO is permitted to recover its costs of procuring electric generation following the expiration of its electric generation rate caps on December 31, 2010 through its PAPUC-approved DSP program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2—Regulatory Issues for further information.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and management agreements. As of December 31, 2009, PECO had credit exposure of $13 million under its natural gas supply and management agreements.

244

Combined Notes to Consolidated Financial Statements—(Continued)

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

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)

As part of the normal course of business, Generation routinely enters into physical and financial contracts for the purchase and sale of electricity, fossil fuels, and other commodities. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Where applicable, this incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margining requirements.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features, excluding transactions on NYMEX and ICE that are fully collateralized, that are in a liability position and are not fully collateralized was $894 million and $1,299 million as of December 31, 2009 and December 31 2008, respectively. As of December 31, 2009 and 2008, Generation had the contractual right of offset of $778 million and $1,175 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $116 million and $124 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have been required to provide incremental collateral of approximately $60 million or $673 million, respectively, as of December 31, 2009 and approximately $14 million or $612 million, respectively, as of December 31, 2008 related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 18 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

Beginning in 2007, under the Illinois auction rules and the SFCs that ComEd entered into with counterparty suppliers, including Generation, collateral postings are one-sided from suppliers. Generation entered into similar SFCs with Ameren, with one-sided collateral postings only from Generation. If market prices fall below ComEd’s or Ameren’s benchmark price levels, ComEd or Ameren are not required to post collateral; however, when market prices rise above benchmark price levels with ComEd or Ameren, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of the five-year financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contracts, collateral postings will never exceed $200 million from either ComEd or Generation. Beginning in June 2009, under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2009, there was no cash collateral or letters of credit posted between energy suppliers, including Generation, and ComEd, under any of the above-mentioned contracts. See Note 2—Regulatory Issues for further information.

245

Combined Notes to Consolidated Financial Statements—(Continued)

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

There are no collateral-related provisions included in the PPA between PECO and Generation. PECO’s supplier master agreements that govern the terms of its DSP program contracts do not contain provisions that would require PECO to post collateral.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2009, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2009, PECO could have been required to post approximately $49 million of collateral to its counterparties.

Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2009, Exelon’s interest rate swap was in an asset position, with a fair value of $10 million.

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

On January 1, 2008, Exelon and Generation adopted guidance permitting companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. Exelon and Generation record cash flow hedges and other derivative and proprietary trading activities in the balance sheet on a net basis and offset the fair value amounts recognized for energy-related derivatives with cash collateral paid to or received from counterparties under master netting arrangements.

As of December 31, 2009 and 2008, $6 million and $5 million, respectively, of cash collateral received was not offset against net derivative positions, as they were not associated with energy-related derivatives.

Change in Balance Sheet Presentation of Option Premiums (Exelon and Generation)

Exelon and Generation have historically presented premiums received and paid on energy-related option contracts within other current assets, other current liabilities, other noncurrent assets or other noncurrent liabilities depending on the nature and term of the underlying option contract. The associated changes in the fair value of the option contracts were recorded in mark-to-market derivative balance sheet line items. Effective December 31, 2009, Exelon and Generation have reclassified the option premiums to the respective mark-to-market derivative asset and liability lines within the Consolidated Balance Sheets to reflect the combined fair value of the option contracts as of the

246

Combined Notes to Consolidated Financial Statements—(Continued)

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

balance sheet date. The December 31, 2008 balances were adjusted to reflect the impacts of this change in presentation, which is presented in the following table.


	Generation							Exelon
	As Previously Stated		Option Premium Adjustments			As Adjusted		As Previously Stated		Option Premium Adjustments			As Adjusted
Mark-to-market derivative current assets	$	410	$	70		$	480	$	410	$	70		$	480
Other		410		(308	)		102		517		(308	)		209

Total Current Assets		3,724		(238	)		3,486		5,368		(238	)		5,130

Mark-to-market derivative noncurrent assets		490		172			662		507		172			679
Other		406		(205	)		201		1,349		(205	)		1,144

Total Noncurrent Assets		7,724		(33	)		7,691		16,636		(33	)		16,603

Total Assets	$	20,355	$	(271	)	$	20,084	$	47,817	$	(271	)	$	47,546

Mark-to-market derivative current liabilities		214		(2	)		212		214		(2	)		212
Other		324		(267	)		57		663		(267	)		396

Total current liabilities		2,437		(269	)		2,168		4,080		(269	)		3,811

Mark-to-market derivative noncurrent liabilities		24		(1	)		23		24		(1	)		23
Other		332		(1	)		331		1,413		(1	)		1,412

Total Noncurrent Liabilities		8,850		(2	)		8,848		20,011		(2	)		20,009

Total Liabilities and Equity	$	20,355	$	(271	)	$	20,084	$	47,817	$	(271	)	$	47,546

9. Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)

Short-Term Borrowings

Exelon, Generation, ComEd and PECO had the following amounts of commercial paper and credit facility borrowings outstanding at December 31, 2009 and 2008:


Commercial Paper Issuer	Maximum Program Size at December 31, 2009 ^(a)		Maximum Program Size at December 31, 2008 ^(a)		Outstanding Commercial Paper at December 31, 2009		Outstanding Commercial Paper at December 31, 2008
Exelon Corporate	$	957	$	957	$	—	$	56
Generation		4,834		4,834		—		—
ComEd ^(b)		952		952		—		—
PECO		574		574		—		95

Total	$	7,317	$	7,317	$	—	$	151

(a)	Equals aggregate bank commitments under revolving credit agreements.

247

Combined Notes to Consolidated Financial Statements—(Continued)

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

(b)


Credit facility borrowings	December 31, 2009		December 31, 2008
ComEd	$	155	$	60

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit agreement, each Registrant cannot issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement.

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd and PECO during 2009, 2008 and 2007:

Exelon


	2009			2008			2007
Average borrowings	$	132		$	636		$	500
Maximum borrowings outstanding		523			1,646			1,210
Average interest rates, computed on a daily basis		0.73	%		3.22	%		5.55	%
Average interest rates, at December 31		0.69	%		0.93	%		5.44	%

*Generation*
	2009			2008			2007
Average borrowings	$	—		$	340		$	44
Maximum borrowings outstanding		—			1,211			740
Average interest rates, computed on a daily basis		n.a.			3.13	%		5.51	%
Average interest rates, at December 31		n.a.			n.a.			n.a.

*ComEd*
	2009			2008			2007
Average borrowings	$	82		$	140		$	291
Maximum borrowings outstanding		265			568			605
Average interest rates, computed on a daily basis		0.79	%		3.91	%		6.01	%
Average interest rates, at December 31		0.69	%		0.96	%		5.63	%

*PECO*
	2009			2008			2007
Average borrowings	$	11		$	82		$	76
Maximum borrowings outstanding		290			284			374
Average interest rates, computed on a daily basis		0.67	%		3.22	%		5.09	%
Average interest rates, computed at December 31		n.a.			0.9	%		5.41	%

n.a.	Not applicable.

248

Combined Notes to Consolidated Financial Statements—(Continued)

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

Credit Agreements

As of December 31, 2009, Exelon Corporate, Generation and PECO had access to separate unsecured credit facilities with aggregate bank commitments of $957 million, $4.8 billion and $574 million, respectively. The credit agreements expire on October 26, 2012 unless extended in accordance with their terms. Under their credit facilities, Exelon Corporate, Generation and PECO may request additional one-year extensions of that term. In addition, Exelon Corporate, Generation and PECO may request increases in the aggregate bank commitments under their credit facilities up to an additional $250 million, $1 billion and $200 million, respectively. Generation also had additional letter of credit facilities used solely to enhance tax-exempt variable rate debt as discussed further below.

As of December 31, 2009, ComEd had access to an unsecured credit facility with aggregate bank commitments of $952 million. The credit facility expires February 16, 2011. ComEd expects to extend or refinance the facility up to $1 billion in 2010. Any increases in aggregate bank commitments are subject to identifying lenders, whether existing or new, willing to provide the additional commitments and, in the case of any new lenders, the consent of the Administrative Agent (appointed and authorized by credit facility lenders to exercise powers delegated in the credit agreement) and certain of the lenders under the credit facility.

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. An event of default under any of the Registrants’ credit facilities will not constitute an event of default under any of the other Registrants’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation under its credit facility will constitute an event of default under the Exelon corporate credit facility.

At December 31, 2009, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under the credit agreements:


Borrower	Aggregate Bank Commitment ^(a)		Outstanding Borrowings/ Facility Draws		Outstanding Letters of Credit		Available Capacity under Revolving Credit Agreements
Exelon Corporate	$	957	$	—	$	5	$	952
Generation		4,834		—		167		4,667
ComEd		952		155		251		546
PECO		574		—		10		564

Total	$	7,317	$	155	$	433	$	6,729

(a)	Excludes $67 million of credit facility agreements arranged with minority and community banks in October 2009, which are primarily for issuing letters of credit.

Interest rates on advances under the credit facilities are based on the prime rate or 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 162.5 basis points.

249

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, 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, 2009:


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

At December 31, 2009 the interest coverage ratios at the Registrants were as follows:


	Exelon	Generation	ComEd	PECO
Interest coverage ratio	13.97	35.65	5.52	5.65

Variable Rate Debt

Generation repurchased $46 million in unenhanced tax-exempt variable-rate debt on February 23, 2009 due to a failed remarketing. In June 2009, Generation refinanced the debt with $46 million in bonds at a term rate through May 2012 with a maturity of 2042.

During the second quarter of 2009, ComEd repurchased $191 million of its credit enhanced variable-rate tax-exempt debt. This debt was then remarketed with credit enhancement provided by letters of credit issued under ComEd’s unsecured revolving credit facility. The letters of credit expire shortly before the expiration of the credit facility in 2011.

Generation had letters of credit that expired during the third quarter of 2009, which were used to credit enhance variable-rate long-term tax-exempt debt totaling $307 million, with maturities ranging from 2021 – 2034. Generation could not find alternative letters of credit at reasonable terms, and therefore repurchased the $307 million in tax-exempt debt during September 2009. Generation has the ability to remarket these bonds whenever it determines it to be economically advantageous given market conditions. In addition, Generation has letter of credit facilities that will expire in the second quarter of 2010, which are used to credit enhance variable-rate long-term tax-exempt debt totaling $213 million, of which $189 million will mature between 2016 – 2034. Generation intends to extend or replace the expiring letters of credit with new letters of credit at reasonable terms, or remarket the bonds with an interest rate term not requiring letter of credit support. If Generation is unable to remarket these bonds at reasonable terms, Generation will repurchase them.

Under the terms of Generation’s and ComEd’s variable-rate tax-exempt debt agreements, Generation or ComEd may be required to repurchase any outstanding debt before its stated maturity unless supported by sufficient letters of credit. If either Generation or ComEd were required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. Generation and ComEd have classified certain amounts outstanding under these debt agreements as long-term based on management’s intent and ability to either renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under existing long-term credit facilities.

250

Combined Notes to Consolidated Financial Statements—(Continued)

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

Long-Term Debt

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd and PECO as of December 31, 2009 and 2008:

Exelon


	Rates	Maturity Date	December 31,
	Rates	Maturity Date	2009			2008
Long-term debt
First Mortgage Bonds ^(a) (b):
Fixed rates	4.70%-7.625%	2010-2038	$	6,630		$	6,396
Floating rates	0.22%-0.26%	2017-2021		191			191
Notes payable and other ^(c)	4.45%-7.83%	2010-2039		4,578			4,290
Pollution control notes:
Floating rates	0.29%-0.35%	2016-2034		213			566
Fixed rates	5.00%	2042		46			—
Sinking fund debentures	4.75%	2011		2			4

Total long-term debt				11,660			11,447
Unamortized debt discount and premium, net				(35	)		(37	)
Unamortized settled fair value hedge, net				(1	)		(1	)
Fair value hedge carrying value adjustment, net				10			17
Long-term debt due within one year				(639	)		(29	)

Long-term debt			$	10,995		$	11,397

Long-term debt to financing trusts ^(d)
Payable to PETT	6.52%	2010		415			1,124
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				805			1,514
Long-term debt due to financing trusts due within one year				(415	)		(319	)

Long-term debt to financing trusts			$	390		$	1,195

(a)	Substantially all of ComEd’s 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 $38 million and $40 million at December 31, 2009 and 2008, respectively. Lease payments of $2 million, $2 million, $3 million, $3 million, $3 million and $25 million will be made in 2010, 2011, 2012, 2013, 2014 and thereafter, respectively.

(d)	Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon’s Consolidated Balance Sheets.

On September 23, 2009, Generation issued and sold $1.5 billion of Senior Notes. In connection with this debt issuance, Generation entered into forward-starting interest rate swaps in the aggregate notional amount of $1.1 billion. The interest rate swaps were settled on September 16, 2009 with Generation recording a pre-tax gain of approximately $7 million. The gain was recorded to OCI within Generation’s Consolidated Balance Sheet and is being amortized over the life of the related debt as a reduction in interest expense.

251

Combined Notes to Consolidated Financial Statements—(Continued)

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

Additionally, during 2009, Exelon retired $1.2 billion of Senior Notes of which $500 million consisted of 6.75% Exelon Corporate Senior Notes due May 1, 2011 and $700 million consisted of 6.95% Generation Senior Notes due June 15, 2011. In connection with these retirements, Exelon incurred losses associated with the early retirement of debt of approximately $117 million, which consisted of $46 million at Exelon Corporate and $71 million at Generation. The expense related to the charges is included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Generation


	Rates	Maturity Date	December 31,
	Rates	Maturity Date	2009			2008
Long-term debt
Senior unsecured notes	5.20%-6.25%	2014-2039	$	2,700		$	1,900
Pollution control notes, floating rates	0.29%-0.35%	2016-2034		213			566
Pollution control notes, fixed rates	5.00%	2042		46			—
Notes payable and other ^(a)	7.83%	2010-2020		38			50

Total long-term debt				2,997			2,516
Unamortized debt discount and premium, net				(4	)		(2	)
Long-term debt due within one year				(26	)		(12	)

Long-term debt			$	2,967		$	2,502

(a)	Includes Generation’s capital lease obligations of $38 million and $40 million at December 31, 2009 and 2008, respectively. Generation will make lease payments of $2 million, $2 million, $3 million, $3 million, $3 million and $25 million in 2010, 2011, 2012, 2013, 2014 and thereafter, respectively.

ComEd


	Rates	Maturity Date	December 31,
	Rates	Maturity Date	2009			2008
Long-term debt
First Mortgage Bonds ^(a)(b):
Fixed rates	4.70%-7.625%	2010-2038	$	4,405		$	4,421
Floating rates	0.22%-0.26%	2017-2021		191			191
Notes payable
Fixed rates	6.95%	2018		140			140
Sinking fund debentures	4.75%	2011		2			4

Total long-term debt				4,738			4,756
Unamortized debt discount and premium, net				(26	)		(29	)
Unamortized settled fair value hedge, net				(1	)		(1	)
Long-term debt due within one year				(213	)		(17	)

Long-term debt			$	4,498		$	4,709

Long-term debt to financing trust ^(c)
Subordinated debentures to ComEd Financing III	6.35%	2033	$	206		$	206

(a)	Substantially all of ComEd’s 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 indenture securing pollution control bonds and notes.

(c)	Amount owed to this financing trust is recorded as debt to financing trust within ComEd’s Consolidated Balance Sheets.

252

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO


	Rates		Maturity Date	December 31,
	Rates		Maturity Date	2009			2008
Long-term debt
First Mortgage Bonds ^(a)(b):
Fixed rates	4.00%-5.95%		2011-2037	$	2,225		$	1,975

Total long-term debt					2,225			1,975
Unamortized debt discount and premium, net					(4	)		(4	)

Long-term debt				$	2,221		$	1,971

Long-term debt to financing trusts ^(c)
PETT Series 2000-A	7.65	%	2009	$	—		$	319
PETT Series 2001	6.52	%	2010		415			805
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					599			1,308
Long-term debt due to financing trusts due within one year					(415	)		(319	)

Long-term debt to financing trusts				$	184		$	989

(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)	Amounts owed to these financing trusts are recorded as debt to financing trusts within PECO’s Consolidated Balance Sheets.

Long-term debt maturities at Exelon, Generation, ComEd and PECO in the periods 2010 through 2014 and thereafter are as follows:


Year	Exelon			Generation		ComEd			PECO
2010	$	1,054	^(a)	$	26	$	213		$	415	^(c)
2011		599			2		347			250
2012		828			3		450			375
2013		555			3		252			300
2014		770			503		17			250
Thereafter		8,659	^(a)		2,460		3,665	^(b)		1,234	^(c)

Total	$	12,465		$	2,997	$	4,944		$	2,824

(a)	Includes $415 million and $390 million due in 2010 and thereafter, respectively, due to ComEd and PECO financing trusts.

(b)	Includes $206 million due to ComEd financing trust.

(c)	Includes $415 million and $184 million due in 2010 and thereafter, respectively, due to PECO financing trusts.

See Note 3—Accounts Receivable for information regarding PECO’s accounts receivable agreement.

See Note 8—Derivative Financial Instruments for additional information regarding interest rate swaps.

See Note 15—Preferred Securities for additional information regarding preferred securities.

253

Combined Notes to Consolidated Financial Statements—(Continued)

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

10. 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, 2009	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	803		$	631		$	(39	)	$	329
Deferred		775			648			228			(143	)
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)
State
Current		154			131			4			26
Deferred		(8	)		30			39			(64	)

Total	$	1,712		$	1,433		$	229		$	146


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	790		$	669		$	(125	)	$	327
Deferred		341			229			230			(147	)
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)
State
Current		169			150			(7	)		43
Deferred		29			89			33			(71	)

Total	$	1,317		$	1,130		$	128		$	150


For the Year Ended December 31, 2007	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	1,269		$	1,144		$	2		$	372
Deferred		34			(20	)		65			(133	)
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)
State
Current		285			249			(3	)		45
Deferred		(130	)		(4	)		19			(52	)

Total	$	1,446		$	1,362		$	80		$	230

254

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, 2009	Exelon		Generation		ComEd		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	2.1		3.0		4.7		(5.0	)
Qualified nuclear decommissioning trust fund income	3.1		3.8		—		—
Domestic production activities deduction	(0.9	)	(1.1	)	—		—
Tax exempt income	(0.1	)	(0.2	)	—		—
Nontaxable postretirement benefits	(0.2	)	(0.2	)	(0.5	)	(0.3	)
Amortization of investment tax credit	(0.2	)	(0.1	)	(0.5	)	(0.4	)
Plant basis differences	—		—		(0.3	)	(0.1	)
Other	—		0.1		(0.4	)	0.1

Effective income tax rate	38.8	%	40.3	%	38.0	%	29.3	%


For the Year Ended December 31, 2008	Exelon		Generation		ComEd		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	3.2		4.6		5.0		(3.9	)
Qualified nuclear decommissioning trust fund losses	(3.2	)	(3.8	)	—		—
Domestic production activities deduction	(1.3	)	(1.6	)	—		—
Tax exempt income	(0.2	)	(0.3	)	—		—
Nontaxable postretirement benefits	(0.3	)	(0.2	)	(0.8	)	(0.3	)
Amortization of investment tax credit	(0.2	)	(0.1	)	(0.9	)	(0.5	)
Plant basis differences	—		—		—		0.3
Other	(0.4	)	(0.2	)	0.6		1.0

Effective income tax rate	32.6	%	33.4	%	38.9	%	31.6	%


For the Year Ended December 31, 2007	Exelon		Generation		ComEd		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	2.5		4.8		4.0		(0.6	)
Synthetic fuel-producing facilities credit	(1.9	)	—		—		—
Qualified nuclear decommissioning trust fund income	1.0		1.2		—		—
Domestic production activities deduction	(1.4	)	(1.7	)	—		—
Tax exempt income	(0.3	)	(0.4	)	—		—
Nontaxable postretirement benefits	(0.3	)	(0.2	)	(1.2	)	(0.3	)
Amortization of investment tax credit	(0.3	)	(0.1	)	(1.2	)	(0.3	)
Indirect cost capitalization method change	—		1.0		(4.6	)	(3.0	)
Research and development credit charge (refund)	0.6		0.7		—		—
Plant basis differences	—		—		—		0.3
Other	(0.2	)	(0.1	)	0.7		0.1

Effective income tax rate	34.7	%	40.2	%	32.7	%	31.2	%

255

Combined Notes to Consolidated Financial Statements—(Continued)

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

The tax effects of temporary differences, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2009 and 2008 are presented below:


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Plant basis differences	$	(5,838	)	$	(1,638	)	$	(2,333	)	$	(1,710	)
Stranded cost recovery		(567	)		—			—			(567	)
Unrealized gains on derivative financial		(613	)		(971	)		(5	)		(1	)
instruments					—			—
Deferred pension and post-retirement obligation ^(a)		1,312			(161	)		(248	)		26
Emission allowances		(24	)		(24	)		—			—
Nuclear decommissioning activities ^(a)		(334	)		(334	)		—			—
Deferred debt refinancing costs		(59	)		(3	)		(47	)		(9	)
Goodwill		4			(1	)		—			—
Other, net ^(a)		441			210			56			94

Deferred income tax liabilities (net)	$	(5,678	)	$	(2,922	)	$	(2,577	)	$	(2,167	)
Unamortized investment tax credits		(224	)		(184	)		(32	)		(9	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(5,902	)	$	(3,106	)	$	(2,609	)	$	(2,176	)


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Plant basis differences	$	(5,139	)	$	(1,289	)	$	(2,067	)	$	(1,609	)
Stranded cost recovery		(896	)		—			—			(896	)
Unrealized gains on derivative financial instruments		(561	)		(749	)		(5	)		(1	)
Deferred pension and post-retirement obligation		1,542			(93	)		(218	)		32
Emission allowances		(31	)		(31	)		—			—
Nuclear decommissioning activities		(87	)		(87	)		—			—
Deferred debt refinancing costs		(65	)		—			(55	)		(10	)
Goodwill		4			—			—			—
Other, net		453			215			43			122

Deferred income tax liabilities (net)	$	(4,780	)	$	(2,034	)	$	(2,302	)	$	(2,362	)
Unamortized investment tax credits		(236	)		(190	)		(35	)		(11	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(5,016	)	$	(2,224	)	$	(2,337	)	$	(2,373	)

(a)

As of December 31, 2008, prior to the dissolution of AmerGen on January 8, 2009, the tax effects of temporary differences related to the partnership investment of the former AmerGen nuclear generating units were classified as an investment in AmerGen, and presented in Other, net. Subsequent to the dissolution of AmerGen in 2009, the tax effects of those temporary differences were allocated to the underlying deferred tax assets and liabilities making up the temporary differences, resulting in a reclassification from Other, net to Nuclear decommissioning activities and Deferred pension and post-retirement obligation.

256

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2009. ComEd does not have any carryforwards as of December 31, 2009:


As of December 31, 2009	Exelon			Generation			PECO
State net operating loss carryforward	$	735	(a)	$	145		$	—
Deferred taxes		34			9			—
Valuation allowance		16			—			—
State capital loss carryforward		455			435	(b)		20
Deferred taxes		20			18			1
Valuation allowance		19			18			1

(a)	Exelon’s state net operating loss carryforwards will expire beginning in 2019

(b)	Generation’s state capital loss carryforwards for income tax purposes will expire in 2010

Tabular reconciliation of unrecognized tax benefits

The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2009:


	Exelon			Generation			ComEd			PECO
Unrecognized tax benefits at January 1, 2009	$	1,495		$	468		$	635		$	365
Decreases based on tax positions related to 2009		(2	)		(2	)		—			—
Change to positions that only affect timing		19			172			(154	)		7
Increases based on tax positions prior to 2009		4			3			—			—
Decreases related to settlements with taxing authorities		(18	)		(8	)		(10	)		—

Unrecognized tax benefits at December 31, 2009	$	1,498		$	633		$	471		$	372

The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2008:


	Exelon			Generation			ComEd			PECO
Unrecognized tax benefits at January 1, 2008	$	1,582		$	431		$	688		$	424
Increases based on tax positions prior to 2008		18			5			12			—
Change to positions that only affect timing		(74	)		32			(65	)		(59	)
Increases based on tax positions related to 2008		3			3			—			—
Decreases related to settlements with taxing authorities		(25	)		(3	)		—			—
Decrease from expiration of statute of limitations		(9	)		—			—			—

Unrecognized tax benefits at December 31, 2008	$	1,495		$	468		$	635		$	365

Included in Exelon’s unrecognized tax benefits balance at December 31, 2009 and December 31, 2008 is approximately $1.4 billion of tax positions for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to or defer the receipt of the cash tax benefit from the taxing authority to an earlier or later period respectively.

257

Combined Notes to Consolidated Financial Statements—(Continued)

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

Unrecognized tax benefits that if recognized would affect the effective tax rate

Exelon, Generation and ComEd have $95 million, $33 million and $62 million, respectively, of unrecognized tax benefits at December 31, 2009 that, if recognized, would decrease the effective tax rate. Exelon, Generation and ComEd had $93 million, $28 million and $65 million, respectively, of unrecognized tax benefits at December 31, 2008 that, if recognized, would decrease the effective tax rate.

Total amounts of interest and penalties recognized

Exelon, Generation, ComEd and PECO have reflected in their Consolidated Balance Sheets as of December 31, 2009 a net interest receivable (payable) of $28 million, $(17) million, $(28) million and $54 million, respectively, related to their uncertain tax positions. Exelon, Generation, ComEd and PECO reflected in their Consolidated Balance Sheets as of December 31, 2008 a net interest receivable (payable) of $(16) million, $(10) million, $(90) million and $48 million, respectively, related to their uncertain tax positions. The Registrants recognize accrued interest related to uncertain tax positions in interest expense (income) in other income and deductions on their Consolidated Statements of Operations. Exelon, Generation, ComEd and PECO have reflected in their Consolidated Statements of Operations net interest expense (income) of $(42) million, $9 million, $(62) million and $(5) million, respectively, related to their uncertain tax positions for the twelve months ended December 31, 2009. For the twelve months ended December 31, 2008, Exelon, Generation, ComEd and PECO reflected in their Consolidated Statements of Operations net interest expense (income) of $(31) million, $(11) million, $(2) million and $(12) million, respectively, related to their uncertain tax positions. For the twelve months ended December 31, 2007, Exelon, Generation, ComEd and PECO reflected in their Consolidated Statements of Operations net interest expense (income) of $(49) million, $24 million, $(41) million and $(20) million, respectively, related to their uncertain tax positions. The Registrants have not accrued any penalties with respect to uncertain tax positions.

Reasonably possible that total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

Nuclear Decommissioning Liabilities (Exelon and Generation)

AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November of 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen’s refund claims. On February 20, 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. In August 2009, the DOJ filed its answer denying the allegations made by Generation in its complaint.

The trial judge assigned to the case has noted the availability of the court’s Alternative Dispute Resolution (ADR) program as an alternative to a trial, but the parties have not yet met with the ADR judge. The ADR program is a non-binding process that utilizes a variety of techniques such as mediation, neutral evaluation, and non-binding arbitration that allow the parties to better understand their differences and their prospects for settlement. While it is unclear when the parties might meet with the ADR judge, the process could result in an expedited conclusion of the matter. As a result, Generation believes that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next twelve months.

258

Combined Notes to Consolidated Financial Statements—(Continued)

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

Tax Method of Accounting for Repairs

In 2009, Exelon received approval from the IRS to change its method of accounting for repair costs associated with Generation’s power plants. The new tax method of accounting resulted in net positive cash flow for 2009 of approximately $420 million. Although the IRS granted Exelon approval to change its method of accounting, the approval did not affirm the methodology used to calculate the deduction. Exelon has requested the IRS to review its methodology through its Pre-Filing Agreement program. If that request is granted it is reasonably possible that the total amount of unrecognized tax benefits could increase or decrease within the next 12 months.

See 1999 Sale of Fossil Generating Assets in Other Tax Matters section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months.

See Competitive Transition Charges in Other Tax Matters section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months.

Description of tax years that remain subject to examination by major jurisdiction


Taxpayer		Open Years
Exelon (and predecessors) and subsidiaries consolidated Federal income tax returns		1989-2008
Exelon (and predecessors) and subsidiaries Illinois unitary income tax returns		2004-2008
Exelon Ventures Company, LLC Pennsylvania corporate net income tax returns		2004-2008
PECO Pennsylvania corporate net income tax returns		2003-2008

Exelon expects the IRS to complete the audit of its 2002 through 2006 taxable years in the first quarter of 2010. Exelon does not expect there to be any material unresolved issues from that audit except for the carryover effects from ComEd’s deferral of gain positions taken on the sale of its fossil generating assets (discussed below).

Other Tax Matters

1999 Sale of Fossil Generating Assets (Exelon and ComEd)

Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the 1999 sale of ComEd’s fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. Exelon believes that it was economically compelled to dispose of ComEd’s fossil generating plants as a result of the Illinois Act. The proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain was deferred over the lives of the replacement property under the involuntary conversion provisions. Approximately $1.2 billion of the gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.

Exelon received the IRS audit report for 1999 through 2001, which reflected the full disallowance of the deferral of gain associated with both the involuntary conversion position and the like-kind exchange transaction. Specifically, the IRS has asserted that ComEd was not forced to sell the fossil

259

Combined Notes to Consolidated Financial Statements—(Continued)

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

generating plants and the sales proceeds were therefore not received in connection with an involuntary conversion of certain ComEd property rights. Accordingly, the IRS has asserted that the gain on the sale of the assets was fully subject to tax. The IRS also asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax.

In addition to attempting to impose tax on the transactions, the IRS has asserted penalties of approximately $196 million for a substantial understatement of tax. Because Exelon believes it is unlikely that the penalty assertion will ultimately be sustained, Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty it would result in an after-tax charge of $196 million to Exelon’s and ComEd’s results of operations.

Exelon disagrees with the IRS disallowance of the deferral of gain and specifically with the characterization of its purchase and leaseback as a SILO. Exelon has been in discussions with IRS Appeals for several months in an attempt to reach a settlement on both the involuntary conversion and like-kind exchange, in a manner commensurate with Exelon’s and the IRS’ respective hazards of litigation with respect to each issue. During the second quarter of 2009, Exelon determined that a settlement with IRS Appeals was unlikely and that Exelon would be required to initiate litigation in order to resolve the issues.

Accordingly, Exelon concluded that it had sufficient new information that a change in measurement was required during the second quarter of 2009. As a result of the required remeasurement of these two positions in the second quarter, Exelon recorded a $31 million (after-tax) interest benefit of which $40 million (after-tax) was recorded at ComEd. The difference in amounts recorded at Exelon and ComEd is due to the method of allocating interest to the Registrants.

Due to the fact that tax litigation often results in a negotiated settlement, Exelon believes that an eventual settlement on the involuntary conversion position remains a likely outcome. Exelon and ComEd have established a liability for an unrecognized tax benefit consistent with their view as to a likely settlement. Management has considered the progress of the ongoing discussions with the IRS Appeals and determined that there were no new developments during the fourth quarter of 2009 that require a remeasurement of the amounts recorded. Based on management’s expectations as to the ongoing potential of a settlement, it is reasonably possible that the unrecognized tax benefits related to this issue may significantly increase or decrease within the next 12 months. It is not possible at this time to predict the amount, if any, of such a change.

With regard to the like-kind exchange transaction, Exelon does not currently believe it is possible to reach a negotiated settlement with either IRS Appeals or the Government’s lawyers prior to a trial. While Exelon has been and remains willing to settle the issue in a manner generally commensurate with its hazards of litigation, the IRS has indicated that it will only settle the issue in a manner consistent with published settlement guidelines for SILO transactions. Those guidelines require a nearly complete concession of the issue by Exelon. Exelon does not believe that its transaction is the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS reflects the strength of Exelon’s position. Accordingly, Exelon currently believes it is likely that the

260

Combined Notes to Consolidated Financial Statements—(Continued)

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

issue will be fully litigated. Given that Exelon has determined settlement is no longer a realistic outcome, it has assessed in accordance with accounting standards whether it will prevail in litigation. While Exelon recognizes the complexity and hazards of this litigation, it believes that it is more likely than not that it will prevail in such litigation and has therefore eliminated any liability for unrecognized tax benefits.

A fully successful IRS challenge to Exelon’s and ComEd’s involuntary conversion position and like-kind exchange transaction would accelerate income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of December 31, 2009, Exelon’s and ComEd’s potential tax and interest that could become currently payable in the event of a successful IRS challenge could be as much as $1.1 billion. Any payments ultimately determined to be due to the IRS related to the involuntary conversion position and the like-kind exchange transaction would be partially offset by the approximately $300 million refund due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the SSCM. A favorable settlement of the tax position related to the CTCs (discussed below) for the 1999-2001 years could also offset a portion of any tax liability due with respect to the final outcome on these positions. If the IRS were to prevail in litigation on both tax positions, Exelon’s and ComEd’s results of operations could be negatively affected by as much as $300 million (after-tax) related to interest expense.

Competitive Transition Charges (Exelon, ComEd and PECO)

Exelon contends that the Illinois Act and the Competition Act resulted in the taking of certain of ComEd’s and PECO’s assets used in their respective businesses of providing electricity services in their defined service areas. Exelon has filed refund claims with the IRS taking the position that CTCs collected during ComEd’s and PECO’s transition periods represent compensation for that taking and, accordingly, are excludible from taxable income as proceeds from an involuntary conversion. If Exelon is successful in its claims, it will be required to reduce the tax basis of property acquired with the funds provided by the CTCs such that the benefits of the position are temporary in nature. The IRS has disallowed the refund claims for the 1999-2001 tax years. Exelon has protested the disallowance and is currently discussing the refund claims with IRS Appeals. The years 2002-2006 are currently under IRS audit and Exelon expects the claims for those years to be disallowed.

Under the Illinois Act, ComEd was required to allow competitors the use of its distribution system resulting in the taking of ComEd’s assets and lost asset value (stranded costs). As compensation for the taking, ComEd was permitted to collect a portion of the stranded costs through the collection of CTCs from those customers electing to purchase electricity from providers other than ComEd. ComEd collected approximately $1.2 billion in CTCs for the years 1999-2006.

Similarly, under the Competition Act, PECO was required to allow others the use of its distribution system resulting in the taking of PECO’s assets and the stranded costs. Pennsylvania permitted PECO to collect CTCs as compensation for its stranded costs. The PAPUC determined the total amount of stranded costs that PECO was permitted to collect through the CTCs to be $5.3 billion. PECO has collected approximately $4.4 billion in CTCs for the period 2000 through December 31, 2009. PECO will continue billing CTCs through 2010.

ComEd and PECO have recognized tax benefits associated with the CTC refund claims and have accrued interest on this tax position. Exelon’s, ComEd’s and PECO’s management believe that the issue has been appropriately recognized; however, the ultimate outcome of this matter could result in unfavorable or favorable impacts to the results of operations and financial positions as well as potential

261

Combined Notes to Consolidated Financial Statements—(Continued)

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

favorable impacts to cash flows, and such impacts could be material. Management has considered the progress of this matter before IRS Appeals and determined that there are no new developments that lead to a remeasurement of the amounts recorded. Based on management’s expectations as to the length of the appeal, it is reasonably possible that the unrecognized tax benefits related to this issue may significantly increase or decrease within the next 12 months. It is not possible at this time to predict the amount, if any, of such a change.

Indirect Cost Capitalization (Exelon, Generation, ComEd and PECO)

In 2001, Exelon filed a request with the IRS to change its tax method of accounting for certain overhead costs under the SSCM effective for years 2001-2004. The tax method change resulted in the deduction of certain overhead costs previously capitalized. In the fourth quarter of 2007, Exelon and the IRS agreed to apply industry-wide guidelines for settling the amount of indirect overhead costs previously capitalized. Based on acceptance of the settlement guidelines, Exelon recorded, in the fourth quarter of 2007, an estimated interest benefit of approximately $40 million (after tax) net of a contingent tax consulting fee of $6 million (after tax). ComEd and PECO recorded an estimated interest benefit (after tax and net of fee) of approximately $26 million and $8 million, respectively. ComEd and PECO recorded a current tax benefit of $13 million and $26 million, respectively, offset with a deferred tax expense recorded at Generation of $38 million. In the second quarter of 2008, Exelon reached final settlement with the IRS as to the amounts of the benefit determined through the application of the IRS settlement guidelines. As a result, Exelon recognized an additional interest benefit of $10 million (after tax) of which $7 million and $2 million of the interest benefit was attributable to ComEd and PECO, respectively. ComEd and PECO recorded a current tax benefit of $4 million and $2 million, respectively, offset with a deferred tax expense recorded at Generation of $6 million.

For years beginning after 2004, Exelon, ComEd and PECO were required to discontinue use of the SSCM and adopt a new method of capitalizing indirect costs. In the third quarter of 2007, ComEd and PECO developed a new indirect cost capitalization method. As a result, Exelon recorded an estimated interest benefit of $5 million (after tax). ComEd and PECO recorded an estimated interest benefit (after tax) of $2 million and $3 million, respectively. During the fourth quarter of 2008, the IRS indicated its agreement with this new method of capitalizing indirect overhead costs. Therefore, Exelon recorded an additional interest benefit (after tax) of $12 million of which $15 million and $2 million was attributable to ComEd and PECO, respectively. In 2009, the IRS industry director issued a new directive for determining the amount of indirect costs capitalized to inventory and self-constructed property, which was consistent with Exelon’s methodology.

Illinois Replacement Investment Tax Credits (Exelon, Generation and ComEd)

On February 20, 2009, the Illinois Supreme Court ruled in Exelon’s favor in a case involving refund claims for Illinois investment tax credits. Consequently, Exelon recorded approximately $42 million (after tax) of income in results of operations in the first quarter of 2009 to reflect the refund claims for investment tax credits and associated interest for the years 1995 – 2008; $35 million and $8 million were recorded at ComEd and Generation, respectively.

Responding to the Illinois Attorney General’s petition for rehearing, on July 15, 2009, the Illinois Supreme Court modified its opinion to indicate that it was to be applied only prospectively, beginning in 2009. Exelon filed a Petition for Rehearing with the Illinois Supreme Court on August 4, 2009. The Petition for Rehearing was denied by the Illinois Supreme Court on September 28, 2009. As a result, Exelon, Generation and ComEd recorded a charge to third quarter 2009 results of operations to reverse the income previously recognized.

262

Combined Notes to Consolidated Financial Statements—(Continued)

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

On December 22, 2009, Exelon filed a Petition of Writ for Certiorari with the United States Supreme Court appealing the Illinois Supreme Court’s July 15, 2009 modified opinion. In the third quarter of 2009 Exelon, Generation and ComEd decreased their unrecognized tax benefits related to this position. However, as a result of the filing of the United States Supreme Court petition the unrecognized tax benefits continue to be reported.

Research and Development Settlement (Exelon, Generation and ComEd)

In 2007, ComEd and the IRS reached an agreement to settle a research and development claim for tax years 1989 -1998. The incremental impact recorded by ComEd in the fourth quarter of 2007, above the amount recorded with the adoption of the authoritative guidance for accounting for uncertain income tax positions, resulted in a reduction to goodwill of $35 million, interest income of $15 million (after tax) and a contingent tax consulting fee of $8 million (after tax). Generation recorded a deferred tax liability and tax expense of $27 million related to the reduction of future depreciation due to the basis reduction of the related assets transferred from ComEd. The contingent fee was accounted for in accordance with the authoritative guidance for accounting for contingent liabilities and recognized in the fourth quarter of 2007.

Long-Term State Tax Apportionment (Exelon and Generation)

Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of Exelon’s and Generation’s deferred state income taxes. On April 16, 2009, the PAPUC approved PECO’s electricity procurement proposal that will have an impact on Exelon’s and Generation’s apportionment of income among the states. Accordingly, Exelon and Generation reevaluated the impacts to deferred state taxes in the second quarter of 2009. The effect of such evaluations resulted in the recording of a non-cash deferred state tax benefit in the amount of $34.7 million, net of taxes. Exelon and Generation have treated electricity as tangible personal property for this purpose which is consistent with the February and July 2009 Illinois Supreme Court decisions.

Tax Restructuring (Exelon)

In the fourth quarter of 2007, Exelon completed a tax restructuring to allow the utilization of separate company losses for state income tax purposes. As a result of the restructuring, Exelon recorded a deferred tax benefit of approximately $63 million related primarily to temporary differences originating through OCI. The effect of the tax restructuring in the fourth quarter of 2007 and its impact on the deferred tax assets at Exelon were recorded in net income.

Investments in Synthetic Fuel-Producing Facilities (Exelon)

Exelon, through three separate wholly owned subsidiaries, owned interests in two limited liability companies and one limited partnership (collectively, the sellers) that own synthetic fuel-producing facilities. Prior to December 31, 2007, Section 45K (formerly Section 29) of the IRC provided tax credits for the sale of synthetic fuel produced from coal. The ability to earn these synthetic fuel tax credits expired on December 31, 2007 and, as such, the synthetic fuel-producing facilities that Exelon had interests in ceased operations on or before December 31, 2007. The agreements with the Sellers terminated in 2008.

Interests in synthetic fuel-producing facilities did not have any net impact on Exelon’s net income for the years ended December 31, 2009 and December 31, 2008 and increased Exelon’s net income

263

Combined Notes to Consolidated Financial Statements—(Continued)

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

by $87 million during the year ended December 31, 2007. Net income from interests in synthetic fuel-producing facilities is reflected in the Consolidated Statements of Operations in income taxes, operating and maintenance expense, depreciation and amortization expense, interest expense, equity in losses of unconsolidated affiliates and other, net.

Tax Sharing Agreement (Exelon, Generation, ComEd and PECO)

Generation, ComEd and PECO are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement 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. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2009, Generation, ComEd and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $57 million, $8 million and $27 million, respectively.

11. Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. Generation will pay for its respective obligations using trust funds that have been established for this purpose. The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2008 to December 31, 2009:


	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2008	$	3,578
Net decrease resulting from updates to estimated future cash flows		(300	)
Accretion expense		221
Payments to decommission retired plants		(14	)

Nuclear decommissioning ARO at December 31, 2008 ^(a)		3,485
Net decrease resulting from updates to estimated future cash flows		(409	)
Accretion expense		203
Payments to decommission retired plants		(19	)

Nuclear decommissioning ARO at December 31, 2009 ^(a)	$	3,260

(a)	Includes $17 million and $13 million as the current portion of the ARO at December 31, 2009 and 2008, respectively, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During 2009, Generation recorded a net decrease in the ARO of $409 million, primarily due to an update in the third quarter of 2009, which reflected updated decommissioning cost studies received for six nuclear units and a decline from the previous year in the cost escalation factor assumptions used to estimate future undiscounted decommissioning costs. This decrease in the ARO resulted in the recognition of $47 million of income (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations, representing the reduction in the ARO in excess of the existing ARC balances for the Non-Regulatory Agreement Units.

264

Combined Notes to Consolidated Financial Statements—(Continued)

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

During 2008, Generation recorded a net decrease in the ARO of $300 million, primarily due to an update in the third quarter of 2008, which reflected updated decommissioning cost studies received for seven nuclear units, a decline from the previous year in the cost escalation factor assumptions used to estimate future undiscounted decommissioning costs and a change in management’s expectation of the year in which the DOE will begin accepting SNF (from the previous estimate of 2018 to 2020), partially offset by a change in the probabilities assigned to decommissioning alternatives for Zion Station to reflect a revised probability for accelerated decommissioning. The decrease in the ARO resulted in the recognition of $19 million of income (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations, representing the reduction in the ARO in excess of the existing ARC balances for the Non-Regulatory Agreement Units.

Overview of Trust Funds. Trust funds have been established for each generating station unit to satisfy Generation’s nuclear decommissioning obligations. Trust funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The trusts funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO currently collects funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are expected to continue through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the trust funds. Every five years, the PAPUC reviews the adequacy of the annual amount that PECO is allowed to collect from its customers. Based on this review, the PAPUC may adjust PECO’s collections upward or downward. Based on the most recent PAPUC review, effective January 1, 2008, the annual collection amount was set at $29 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2013. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the trust funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the trust funds.

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation. Generation has recourse to collect additional amounts from PECO customers related to a shortfall of trust funds for the former PECO units, subject to certain limitations and thresholds, 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, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. This initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the trusts after decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the trusts after decommissioning.

Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation’s obligations related to the shortfall or excess of trust funds necessary for decommissioning the former ComEd units on a unit-by-unit basis,

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Combined Notes to Consolidated Financial Statements—(Continued)

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

as long as funds held in the NDT funds exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized income and losses on the trust funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. The offset of decommissioning-related activities within the Consolidated Statement of Operations results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the value of the trust fund for any former ComEd unit fall below the amount of the estimated decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and the adverse impact to Exelon’s and Generation’s results of operations and financial position could be material. At December 31, 2009, the trust funds of each of the former ComEd units exceeded the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is the ARO reflected on Generation’s Consolidated Balance Sheet at December 31, 2009 and is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the seven former PECO nuclear units, regardless of whether the funds held in the NDT funds exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. The offset of decommissioning-related activities within the Consolidated Statement of Operations results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations, and the impact to Exelon’s and Generation’s results of operations and financial position could be material. See Note 2—Regulatory Issues for information regarding a PAPUC investigation to determine if PECO’s decommissioning cost collections from customers should continue after December 31, 2010.

The decommissioning-related activities related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen units) and the portions of the Peach Bottom nuclear plants that are not subject to regulatory agreements with respect to the NDT funds are reflected in Exelon’s and Generation’s Consolidated Statements of Operations, as there are no regulatory agreements associated with these units. Refer to Note 19—Supplemental Financial Information and Note 21—Related Party Transactions for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.

NRC Minimum Funding Requirements. 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. During 2008, the value of the trust funds declined significantly due to unrealized losses as a result of adverse financial market conditions. Despite this decline in value, Generation believes that the decommissioning trust funds for the nuclear generating stations formerly owned by ComEd, PECO and AmerGen, the

266

Combined Notes to Consolidated Financial Statements—(Continued)

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

expected earnings thereon and, in the case of the former PECO stations, the remaining amounts to be collected from PECO’s customers will ultimately be sufficient to fully fund Generation’s decommissioning obligations for its nuclear generating stations in accordance with NRC regulations.

Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial position may be significantly adversely affected.

Generation’s most recent report was filed with the NRC on March 31, 2009, based on trust fund values and estimated decommissioning obligations as of December 31, 2008. The estimated decommissioning obligations for the NRC report were calculated in accordance with NRC regulations, and differ from the ARO recorded on Generation’s and Exelon’s Consolidated Balance Sheets at December 31, 2008, primarily due to differences in assumptions regarding the decommissioning alternatives to be used and potential license renewals.

On July 13, 2009, the NRC published a summary of decommissioning trust fund shortfalls at industry nuclear units, which for Generation’s nuclear generating stations set forth an aggregate underfunded position of approximately $1.0 billion. The NRC calculation assumes one scenario where decommissioning activities are completed within seven years after the cessation of plant operations. Under NRC regulations, nuclear unit owners have up to 60 years to complete decommissioning after the cessation of operations, during which time decommissioning funds would continue to be invested. The NRC did not publish any calculations for alternative scenarios where decommissioning activities are completed at a later time during the 60-year window. Generation, consistent with NRC regulations, makes its calculations based upon the 60-year decommissioning scenario. Consistent with studies approved by the NRC and assuming that decommissioning activities are completed within the permissible 60-year regulatory time period, Generation believes that six units at three nuclear generating stations were in an underfunded position by approximately $185 million in total relative to the NRC minimum funding requirement as of December 31, 2008. Over 90% of this total is attributable to Generation’s four units at Braidwood and Byron, where Generation has not yet filed for license extensions. Although the NRC does not allow for potential license extensions to be credited in calculating NRC minimum funding requirements, to the extent that license extensions are granted for these units, decommissioning funds will continue to be invested for an additional 20-year period. Generation presently anticipates that it will file for license extensions for these units consistent with its ongoing business plan.

Generation and other industry members are engaged in ongoing discussions with the NRC regarding the NRC’s calculations. On July 31, 2009, Generation submitted its plan to the NRC to remediate the remaining underfunded position. The multi-step plan is expected to fully remediate any underfunded positions calculated as of December 31, 2009 by April 1, 2010. Additionally, the plan provides for an annual assessment of Generation’s remediation of any underfunded position. Based on the latest calculations and trust fund values, Generation believes that the underfunded position is $45 million as of December 31, 2009. Generation does not expect that any cash contributions to the funds will be required; instead, Generation anticipates that any underfunded position will be addressed through other financial guarantee methods as allowed by NRC regulations and laid out in the plan submitted to the NRC by Generation.

267

Combined Notes to Consolidated Financial Statements—(Continued)

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

As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. At present, Generation anticipates that it will remedy any underfunded position remaining after full implementation of its funding assurance plan as submitted to the NRC through the issuance of a limited guarantee from Exelon in the amount of up to $45 million, rather than through cash contributions to the decommissioning trust funds.

Nuclear Decommissioning Trust Fund Investments

At December 31, 2009 and December 31, 2008, Exelon and Generation had NDT fund investments totaling $6,669 million and $5,500 million, respectively.

In the first quarter of 2009, Generation performed a rebalancing of its NDT fund investments in order to bring the mix of equity and fixed income investments into alignment with targeted ratios. At December 31, 2009, approximately 53% of the funds were invested in equity and 47% were invested in fixed income securities. At December 31, 2008, approximately 39% of the funds were invested in equity and 61% were invested in fixed income securities.

Generation’s NDT funds participate in a securities lending program with the trustees of the funds. The program authorizes the trustees to loan securities that are assets of the trust funds to approved borrowers. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The securities are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral fund, but may also be invested in assets with maturities matching, or approximating, the duration of the loan of the related securities. Collateral may not be sold or re-pledged by the trustees; however, the borrowers may sell or re-pledge the securities loaned. Generation bears the risk of loss with respect to its invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from current market conditions. Generation, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by Generation, whether the result of declines in fair value or liquidity impairments, have not been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.

In the fourth quarter of 2008, Generation decided to end its participation in the securities lending program and chose to initiate a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to the lack of liquidity in the market. As part of its withdrawal plan and in order to minimize realized losses, Generation temporarily increased its securities on loan during 2009. This temporary increase does not change Generation’s intent to end its participation in the securities lending program. Currently, the weighted average maturity of the securities within the collateral pools is approximately 4 months. At December 31, 2008, Generation had $380 million of loaned securities

268

Combined Notes to Consolidated Financial Statements—(Continued)

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

outstanding and held $386 million of related collateral under its lending agreements. At December 31, 2009, Generation had $357 million of loaned securities outstanding and held $366 million of related collateral under its lending agreements, representing a decrease in loaned securities outstanding since December 31, 2008 of $23 million primarily due to the return of loaned securities.

A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trust funds and the trustees in their capacity as security agents. Securities lending income allocated to the NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the years ended December 31, 2009 and 2008.

The following table provides unrealized gains (losses) on NDT funds and other-than-temporary impairment of NDT funds for the years ended 2009, 2008 and 2007:


	Exelon and Generation
	For the Years Ended December 31,
	2009			2008			2007
Net unrealized gains (losses) on decommissioning trust funds— Regulatory Agreement Units ^(a)	$	799		$	(1,023	)	$	43
Net unrealized gains (losses) on decommissioning trust funds— Non-Regulatory Agreement Units ^(b)		227	^(d)		(324	)^(d)		(14	)^(e)
Other-than-temporary impairment of decommissioning trust funds—Regulatory Agreement Units ^(c)		n/a			n/a			(84	)^(a)^(b)
Other-than-temporary impairment of decommissioning trust funds— Non-Regulatory Agreement Units ^(c)		n/a			n/a			(9	) ^(d)

(a)

Generation’s NDT funds associated with the former ComEd and former PECO nuclear generating units that are subject to regulatory agreements with respect to NDT funding are subject to contractual elimination pursuant to regulatory accounting and included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)	Generation’s NDT funds that are not subject to a regulatory agreement with respect to NDT funding are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

(c)

As a result of certain NRC restrictions, Exelon and Generation were unable to demonstrate the ability and intent to hold the NDT fund investments through a recovery period and, in accordance with other-than-temporary impaired investment authoritative guidance, recognized any unrealized holding losses immediately.

(d)	Included in Other, net in Exelon’s and Generation’s Consolidated Statement of Operations.

(e)	Included in accumulated OCI on Exelon’s and Generation’s Consolidated Balance Sheet.

Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units, which are subject to regulatory accounting, are eliminated within Other, net in Exelon and Generation’s Consolidated Statement of Operations.

Non-Nuclear Asset Retirement Obligations (Exelon, Generation, ComEd, and PECO)

Generation has AROs for plant closure costs associated with its fossil and hydroelectric generating stations, including asbestos abatement, removal of certain storage tanks and other decommissioning-related activities. ComEd and PECO have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs.

269

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents the activity of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2008 to December 31, 2009:


	Exelon			Generation			ComEd			PECO
Non-nuclear AROs at January 1, 2008	$	250		$	64		$	163		$	22
Net increase resulting from updates to estimated future cash flows		8			5			2			1
Accretion ^(a)		14			4			10			1
Payments		(10	)		(9	)		(1	)		—

Non-nuclear AROs at December 31, 2008		262			64			174			24
Net increase (decrease) resulting from updates to estimated future cash flows		(81	)		5			(85	)		(1	)
Accretion ^(a)		12			4			8			1
Payments		(2	)		—			(2	)		—

Non-nuclear AROs at December 31, 2009	$	191		$	73		$	95		$	24

(a)	For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulations.

During 2009, ComEd recorded an $85 million reduction to its ARO liabilities and offsetting credits to the associated regulatory accounts based on management’s revised assumptions. This change in estimate did not have an impact on ComEd’s results of operations or cash flows.

12. Spent Nuclear Fuel Obligation (Exelon and Generation)

Under the NWPA, the DOE is responsible for the development of a geologic 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 Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. In January 2009, the DOE issued its Draft National Transportation Plan for the proposed repository. The DOE’s press statement accompanying the release of the plan indicated that shipments to the repository are not expected to begin before 2020.

The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama Administration devises a new strategy for long-term SNF management. Debate surrounding any new strategy likely will address centralized interim storage, permanent storage at multiple sites and/or SNF reprocessing. Given the program’s history of funding restrictions, it is possible that shipments to the repository may not begin by 2020. Because there is no particular date after 2020 that Generation can establish as having a higher probability as the start date for facility operations, Generation uses the 2020 date as its best estimate of when the DOE will begin accepting SNF. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Limerick, Oyster Creek, Peach Bottom, Byron, Braidwood, LaSalle and Quad Cities stations. Generation performed sensitivity analyses assuming that the estimated date for the DOE acceptance of SNF was delayed to 2025 and to 2035

270

Combined Notes to Consolidated Financial Statements—(Continued)

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

and determined that Generation’s aggregate nuclear ARO would be reduced by an immaterial amount in each scenario. In August 2004, Generation and the U.S. DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

Under the agreement, Generation has received cash reimbursements for costs incurred through April 30, 2009, totaling approximately $360 million ($282 million after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek). As of December 31, 2009, the amount of SNF storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $69 million, which is recorded within accounts receivable, other. This amount is comprised of $17 million, which has been recorded as a reduction to operating and maintenance expense, and $49 million, which has been recorded as a reduction to capital expenditures. The remaining $3 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities.

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, 2009, the unfunded SNF liability for the one-time fee with interest was $1,017 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, 2009, was 0.061%. The liabilities for SNF 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. See Note 7—Fair Value of Assets and Liabilities for additional information.

13. Retirement Benefits (Exelon, Generation, ComEd and PECO)

As of December 31, 2009, Exelon sponsored seven defined benefit pension plans and three postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.

Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly hired union-represented employees participate in cash balance pension plans. Exelon has elected that the trusts underlying the plans be treated under the IRC as qualified trusts. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations. Exelon also sponsors certain non-qualified pension plans.

271

Combined Notes to Consolidated Financial Statements—(Continued)

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

Benefit Obligations and Plan Assets, and Funded Status

Exelon recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans as an asset or liability on its balance sheet, with offsetting entries to Accumulated Other Comprehensive Income (AOCI) and regulatory assets, in accordance with the applicable authoritative guidance. The impact of changes in assumptions used to measure pension and other postretirement benefit obligations is generally recognized over the expected average remaining service period of the plan participants, rather than immediately recognized. The measurement date for the plans is December 31. The obligations reflect the impact of Exelon’s 2009 restructuring activities and changes in certain plans related to some union participants. The following table provides 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
	2009			2008			2009			2008
Change in benefit obligation:
Net benefit obligation at beginning of year	$	10,788		$	10,427		$	3,480		$	3,335
Service cost		178			163			113			108
Interest cost		651			635			205			208
Plan participants’ contributions		—			—			18			22
Actuarial loss (gain)		479			176			31			(14	)
Plan Amendments		2			16			—			—
Curtailments/settlements		2			1			—			—
Special termination benefits		—			—			4			—
Gross benefits paid		(618	)		(630	)		(203	)		(189	)
Federal subsidy on benefits paid		—			—			10			10

Net benefit obligation at end of year	$	11,482		$	10,788		$	3,658		$	3,480

Change in plan assets:
Fair value of net plan assets at beginning of year	$	6,664		$	9,634		$	1,224		$	1,616
Actual return on plan assets		1,352			(2,420	)		280			(388	)
Employer contributions		441			80			157			163
Plan participants’ contributions		—			—			18			22
Gross benefits paid		(618	)		(630	)		(203	)		(189	)

Fair value of net plan assets at end of year	$	7,839		$	6,664		$	1,476		$	1,224

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:


	Pension Benefits				Other Postretirement Benefits
	As of December 31,				As of December 31,
	2009		2008		2009		2008
Other current liabilities	$	18	$	13	$	2	$	1
Pension obligations		3,625		4,111		—		—
Non-pension postretirement benefit obligations		—		—		2,180		2,255

Unfunded status (net benefit obligation less net plan assets)	$	3,643	$	4,124	$	2,182	$	2,256

272

Combined Notes to Consolidated Financial Statements—(Continued)

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

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. During 2008, Exelon’s unfunded status increased significantly, primarily due to lower than expected 2008 asset returns. The unfunded balance of the plans decreased to $5.83 billion as of December 31, 2009 as compared to $6.38 billion at 2008. While a decrease in discount rates and other factors resulted in an increase in the pension and other postretirement obligation, it was more than offset by the significant increase in asset values during 2009. The funded status may change over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

The following table provides the projected benefit obligations (PBO), accumulated benefit obligation (ABO) and fair value of plan assets for all pension plans with an ABO in excess of plan assets.


	December 31,
	2009		2008
Projected benefit obligation	$	11,482	$	10,788
Accumulated benefit obligation		10,695		10,017
Fair value of net plan assets		7,839		6,664

The following table provides the PBO, ABO and fair value of all pension plans with a PBO in excess of plan assets.


	December 31,
	2009		2008
Projected benefit obligation	$	11,482	$	10,788
Accumulated benefit obligation		10,695		10,017
Fair value of net plan assets		7,839		6,664

On an ABO basis, the plans were funded at 73% at December 31, 2009 compared to 67% at December 31, 2008. On a PBO basis, the plans were funded at 68% at December 31, 2009 compared to 62% at December 31, 2008. The ABO differs from the PBO in that it includes no assumption about future compensation levels.

273

Combined Notes to Consolidated Financial Statements—(Continued)

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

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2009, 2008 and 2007 for all plans combined. The table reflects a reduction in 2009, 2008 and 2007 of net periodic postretirement benefit costs of approximately $38 million, $38 million and $44 million, respectively, related to a Federal subsidy provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act), discussed further below.


	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009			2008			2007
Components of net periodic benefit cost:
Service cost	$	178		$	163		$	163		$	113		$	108		$	106
Interest cost		651			635			603			205			208			192
Expected return on assets		(778	)		(836	)		(816	)		(94	)		(121	)		(115	)
Amortization of:
Transition obligation		—			—			—			9			10			10
Prior service cost (credit)		14			15			16			(56	)		(57	)		(56	)
Actuarial loss		197			127			148			87			53			63
Curtailment/settlement charges		6			9			5			—			—			—
Special termination benefits		—			—			1			4			—			—

Net periodic benefit cost	$	268		$	113		$	120		$	268		$	201		$	200

Through Exelon’s postretirement benefit plans, the Registrants provide retirees with prescription drug coverage. The Prescription Drug Act, enacted on December 8, 2003, introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree healthcare 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 meets the requirements for the subsidy.

The effect of the subsidy on the components of net periodic postretirement benefit cost for 2009, 2008 and 2007 included in the consolidated financial statements was as follows:


	2009		2008		2007
Amortization of the actuarial experience loss	$	11	$	11	$	16
Reduction in current period service cost		9		9		10
Reduction in interest cost on the APBO		18		18		18

274

Combined Notes to Consolidated Financial Statements—(Continued)

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

Components of OCI and Regulatory Assets

Under the authoritative guidance for regulatory accounting, a portion of net periodic benefit costs is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be charged to OCI. The following tables provide the components of OCI and regulatory assets for the years ended December 31, 2009, 2008 and 2007 for all plans combined.


	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009			2008			2007
Changes in plan assets and benefit obligations recognized in OCI and regulatory assets:
Current year actuarial (gain) loss	$	(94	)	$	3,432		$	127		$	(154	)	$	495		$	(109	)
Amortization of actuarial gain (loss)		(197	)		(127	)		(148	)		(87	)		(53	)		(63	)
Current year prior service cost		2			16			—			—			—			—
Amortization of prior service cost (credit)		(14	)		(15	)		(16	)		56			57			56
Amortization of transition obligation		—			—			—			(9	)		(10	)		(10	)
Settlements		(6	)		(9	)		(5	)		—			—			—

Total recognized in OCI and regulatory assets	$	(309	)	$	3,297		$	(42	)	$	(194	)	$	489		$	(126	)

The following table provides the components of Exelon’s gross accumulated other comprehensive loss and regulatory assets that have not been recognized as components of periodic benefit cost as of December 31, 2009 and 2008, respectively, for all plans combined:


	Pension Benefits				Other Postretirement Benefits
	As of December 31,				As of December 31,
	2009		2008		2009			2008
Transition obligation	$	—	$	—	$	29		$	38
Prior service cost (credit)		118		130		(110	)		(166	)
Actuarial loss		5,838		6,135		1,029			1,270

Total ^(a)	$	5,956	$	6,265	$	948		$	1,142

(a)

Of the $5,956 million related to pension benefits, $3,819 million and $2,137 million are included in AOCI and regulatory assets, respectively, as of December 31, 2009. Of the $948 million related to other postretirement benefits, $470 million and $478 million are included in AOCI and regulatory assets, respectively, as of December 31, 2009. Of the $6,265 million related to pension benefits, $4,023 million and $2,242 million are included in AOCI and regulatory assets, respectively, as of December 31, 2008. Of the $1,142 million related to other postretirement benefits, $555 million and $587 million are included in AOCI and regulatory assets, respectively, as of December 31, 2008.

275

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides the components of Exelon’s AOCI and regulatory assets as of December 31, 2009 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2010. These estimates are subject to the completion of a valuation report of Exelon’s pension and other postretirement benefit obligations. This valuation report will reflect actual census data as of January 1, 2010 and actual claims activity as of December 31, 2009 and is expected to be completed by the first quarter of 2010.


	Pension Benefits		Other Postretirement Benefits
Transition obligation	$	—	$	9
Prior service cost (credit)		14		(56	)
Actuarial loss		256		73

Total ^(a)	$	270	$	26

(a)

Of the $270 million related to pension benefits, $166 million and $104 million are included in AOCI and regulatory assets, respectively, as of December 31, 2009. Of the $26 million related to other postretirement benefits, $11 million and $15 million are expected to be included in AOCI and regulatory assets, respectively, as of December 31, 2009.

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit or other postretirement plans involves various factors, including the development of valuation assumptions and accounting elections. When determining the various assumptions that are required, Exelon considers historical information as well as future expectations. The measurement of benefit costs is affected by the actual rate of return on plan assets and assumptions including the long-term expected rate of return on plan assets, the discount rate applied to benefit obligations, Exelon’s expected level of contributions to the plans, the incidence of mortality, the expected remaining service period of plan participants, level of compensation and rate of compensation increases, employee age, length of service, the long-term expected investment rate credited to employees of certain plans, the anticipated rate of increase of healthcare costs and the level of benefits provided to employees and retirees, among other factors. The impact of changes in assumptions used to measure pension and other postretirement benefit obligations is generally recognized over the expected average remaining service period of the plan participants, rather than immediately recognized.

Expected Rate of Return. In selecting the expected rate of return on plan assets, Exelon considers historical returns for the types of investments that its plans hold in addition to expectations regarding future long-term asset returns, weighted by Exelon’s target asset class allocation. In general, equity securities, real estate and private equity investments are forecasted to have higher returns than fixed income securities. Historical returns and volatilities are modeled to determine asset allocations that best meet the objectives of the investment trusts that hold the plan assets. A change in asset allocations could significantly impact the expected rate of return on plan assets.

276

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following weighted average assumptions were used to determine the benefit obligations for all of the plans at December 31, 2009, 2008 and 2007:

Pension Benefits

Other Postretirement Benefits

2009 ^(a)

2008

2007

2009 ^(a)

2008

2007

Discount rate

5.83%

6.09%

6.20%

5.83%

6.09%

6.20%

Rate of
compensation increase

4.00%

Mortality table

IRS required
mortality table
for 2010
funding
valuation

IRS required
mortality table
for 2009
funding
valuation

IRS required
mortality table
for 2008
funding
valuation

IRS required
mortality table
for 2010
funding
valuation

IRS required
mortality table
for 2009
funding
valuation

IRS required
mortality table
for 2008
funding
valuation

Healthcare cost
trend on covered
charges

N/A

7.5%

decreasing to
ultimate
trend of 5.0%

in 2015

7.5%

decreasing to
ultimate
trend of 5.0%

in 2014

8.00%

decreasing to
ultimate
trend of 5.0%

in 2014

(a)	Assumptions used to determine year-end 2009 benefit obligations are the assumptions used to estimate the 2010 net periodic benefit cost.

The following weighted average assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2009, 2008 and 2007:

Pension Benefits

Other Postretirement Benefits

2009

2008

2007

2009

2008

2007

Discount rate

6.09%

6.20%

5.90%

6.09%

6.20%

5.85%

Expected return on plan assets

8.50%

8.75%

8.10%^(a)

7.80%^(a)

7.85%^(a)

Rate of compensation increase

4.00%

Mortality table

IRS required
mortality
table for
2009
funding
valuation

IRS required
mortality
table for
2008
funding
valuation

RP 2000 with
10-year
projection of
mortality
improvements

IRS required
mortality
table for
2009 funding
valuation

IRS required
mortality
table for
2008 funding
valuation

RP 2000 with
10-year
projection of
mortality
improvements

Healthcare cost
trend on covered
charges

N/A

7.50%

decreasing
to ultimate
trend of 5.0%

in 2014

8.00%

decreasing
to ultimate
trend of 5.0%

in 2014

9.00%

decreasing to
ultimate trend
of 5.0%

in 2012

(a)	Not applicable to the Exelon-sponsored former-AmerGen other postretirement benefit plan, as this plan does not have any plan assets.

277

Combined Notes to Consolidated Financial Statements—(Continued)

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

Assumed healthcare cost trend rates have a significant effect on the costs reported for the healthcare plans. A one percentage point change in assumed healthcare cost trend rates would have the following effects:


Effect of a one percentage point increase in assumed healthcare cost trend
on 2009 total service and interest cost components	$	49
on postretirement benefit obligation at December 31, 2009		448
Effect of a one percentage point decrease in assumed healthcare cost trend on 2009 total service and interest cost components		(40	)
on postretirement benefit obligation at December 31, 2009		(372	)

Contributions

The following table provides contributions made by Generation, ComEd, PECO and BSC to the pension and other postretirement benefit plans:


	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009 ^(a)		2008 ^(a)		2007 ^(a)
Generation	$	201		$	37		$	24		$	64	$	71	$	78
ComEd		164			9			3			50		49		52
PECO		31			11			1			21		29		31
BSC		45	(b)		23	(b)		8	(b)		12		14		18

Exelon	$	441		$	80		$	36		$	147	$	163	$	179

(a)

The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd and PECO received Federal subsidy payments of $10 million, $5 million, $3 million and $1 million, respectively, in 2009, $12 million, $5 million, $3 million and $2 million, respectively, in 2008, and $6 million, $3 million, $2 million and $1 million, respectively, in 2007.

(b)	$1 million and $5 million of this amount was deferred under Exelon’s deferred compensation plan as of 2008 and 2007. None of the amount was deferred as of December 31, 2009.

Funding is based upon actuarially determined contributions that take into account the minimum contribution required under ERISA, as amended, for the pension plans and the amount deductible for income tax purposes for the other postretirement benefit plans. Management considers these and other factors when making funding decisions. The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. Recent pension funding guidance has modified some of those elections.

The Pension Protection Act of 2006 (the Act) became effective January 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions). Generally, effective January 1, 2008 (January 1, 2009 for most union-represented employees), Exelon prospectively amended the vesting schedule, benefit crediting rate and investment crediting rate of its relevant cash balance pension plans in accordance with interim guidance issued by the U.S. Treasury Department pursuant to the Act. These changes to the cash balance pension plans did not have a significant impact on Exelon’s results of operations or cash flows. In March and September 2009, the U.S. Treasury Department provided guidance on the selection of the corporate bond yield curve for determining the interest rate used to calculate plan liabilities and determine

278

Combined Notes to Consolidated Financial Statements—(Continued)

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

pension funding requirements. There are other legislative and regulatory funding relief proposals also being discussed. Exelon is monitoring the progress of these initiatives and evaluating their potential impact on funding requirements and strategies.

The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA) was signed into law in December 2008. WRERA grants plan sponsors relief from certain funding requirements and benefit restrictions, and also provides some technical corrections to the Act. There are two primary provisions that impact funding results for Exelon. First, required contributions will be based on a percentage of the funding target for years beginning before 2011, rather than a funding target of 100%. These percentages are 92%, 94% and 96% in 2008, 2009 and 2010, respectively. Second, one of the technical corrections, referred to as asset smoothing, allows the use of average asset amounts, including expected returns (subject to certain limitations), for a 24-month period prior to the measurement date, in the determination of funding requirements. Exelon has elected to utilize asset smoothing for its largest pension plan and market value of assets for its remaining plans. These elections are expected to provide Exelon the opportunity to defer certain contributions to later years and potentially mitigate future contributions through investment market recovery.

During September 2009, Exelon made a discretionary pension contribution of $350 million to its largest pension plan. The contribution, combined with funding elections for the 2009 and 2010 plan years, is expected to reduce future contribution requirements.

Exelon allocates pension contributions to its subsidiaries in proportion to active service costs recognized. In addition, Exelon allocates other postretirement contributions to its subsidiaries in proportion to total costs recognized. Exelon expects to contribute approximately $417 million to the benefit plans in 2010, of which Generation, ComEd and PECO expect to contribute $198 million, $92 million and $67 million, respectively. Exelon’s expected 2010 benefit plan contributions of $417 million include $261 million of minimum required pension contributions (including contributions to avoid benefit restrictions) and other postretirement contributions of $156 million (of which approximately $100 million is discretionary). These estimates are subject to the completion of a valuation report of Exelon’s pension and other postretirement benefit obligations. This valuation report will reflect actual census data as of January 1, 2010 and claims activity as of December 31, 2009.

Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2009 were:


	Pension Benefits		Other Postretirement Benefits
2010	$	708	$	190
2011		639		199
2012		651		205
2013		677		212
2014		677		219
2015 through 2019		3,873		1,256

Total estimated future benefits payments through 2019	$	7,225	$	2,281

(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 2010, 2011, 2012, 2013, 2014 and from 2015 through 2019 are estimated to be $10 million, $11 million, $12 million, $13 million, $14 million and $89 million, respectively.

279

Combined Notes to Consolidated Financial Statements—(Continued)

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

Allocation to Exelon Subsidiaries

Generation, ComEd and PECO account for their participation in Exelon’s pension and other postretirement benefit plans by applying multiemployer accounting. Employee-related assets and liabilities, including both pension and 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 and other postretirement costs to the participating employers based upon several factors, including the measures of active employee participation in each participating unit. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001.

The following approximate amounts were included in capital and operating and maintenance expense during 2009, 2008 and 2007, respectively, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the Exelon-sponsored pension and other postretirement benefit plans:


	Generation		ComEd		PECO		BSC^(a)		Exelon
2009	$	240	$	192	$	47	$	57	$	536
2008		139		101		32		42		314
2007		142		101		32		45		320

(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

Plan Assets

Investment Strategy. Exelon’s overall investment strategy is to achieve a mix of investments for long-term growth and for near-term benefit payments with diversification of asset types, fund strategies, and fund managers. Exelon seeks to achieve optimal asset returns while balancing the liquidity requirements of the plans’ liabilities. Exelon utilizes a diversified, strategic asset allocation to efficiently and prudently generate investment returns that will meet the objectives of the investment trusts that hold the plan assets. Asset/liability studies are utilized to determine the specific asset allocations for the trusts. In general, Exelon’s investment strategy reflects the belief that equities are expected to outperform fixed-income investments and are well-suited to bear the risk of added volatility over the long-term. Accordingly, the asset allocations of the trusts usually reflect a higher allocation to equities as compared to fixed-income securities. Equity securities primarily include investments in diversified portfolios of domestic large cap and small cap firms. Equity securities also include non-U.S. equity securities, which are used to diversify some of the volatility of the U.S. equity market while providing comparable long-term returns. Fixed-income securities include diversified portfolios invested across a broad spectrum of primarily investment-grade securities. These portfolios have the Barclays Aggregate Bond Index as their benchmark. In the pension trusts, Exelon generally maintains approximately 10% of its plan assets in alternative asset classes. Alternative asset classes are utilized to provide additional diversification and return potential and include investments in private equity and real estate. On a quarterly basis, Exelon reviews the actual asset allocations and follows a rebalancing procedure in order to remain within an allowable range, as defined by its policy, of its targeted allocation percentages. Exelon’s investment guidelines limit the amount of allowed exposure to investments in more volatile sectors and limit concentrations based on established criteria. A change in the overall investment strategy could significantly impact the expected rate of return on plan assets.

280

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon’s pension plan’s weighted average asset allocations at December 31, 2009 and 2008 and target allocation for 2009 were as follows:


Asset Category	Target Allocation at December 31, 2009		Percentage of Plan Assets at December 31,
Asset Category	Target Allocation at December 31, 2009		2009		2008
Equity securities
Large Cap	30-35	%	32	%	26	%
Small Cap	10		9		8
International	15		15		13
Private Equity	5		6		6

Total Equity Securities	60-65	%	62	%	53	%

Fixed Income Securities	35-40	%	34	%	42	%
Real Estate	5	%	4	%	5	%

Total			100	%	100	%

Exelon’s other postretirement benefit plan’s weighted-average asset allocations at December 31, 2009 and 2008 and target allocation for 2009 were as follows:


Asset Category	Target Allocation at December 31, 2009		Percentage of Plan Assets at December 31,
Asset Category	Target Allocation at December 31, 2009		2009		2008
Equity securities
Large Cap	35-40	%	39	%	35	%
Small Cap	5-10	%	10		9
International	15		15		14

Total Equity Securities	60-65	%	64	%	58	%

Fixed Income Securities	35-40	%	36	%	42	%

Total			100	%	100	%

Securities Lending Programs. The majority of the benefit plans participate in a securities lending program with the trustees of the plans’ investment trusts. The program authorizes the trustee of the particular trust to lend securities, which are assets of the plan, to approved borrowers. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The loaned securities are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is invested in collateral funds comprised primarily of short term investment vehicles. Collateral may not be sold or re-pledged by the trustees, however, the borrowers may sell or re-pledge the loaned securities. Exelon’s benefit plans bear the risk of loss with respect to unfavorable changes in the fair value of the invested cash collateral. Such losses may result from a decline in the fair value of specific investments or due to liquidity impairments resulting from current market conditions. Exelon, the trustees and the borrowers have the right to terminate the lending agreement at any time. In the event of termination, the borrowers must return the loaned securities or surrender the collateral. Losses recognized by the trust

281

Combined Notes to Consolidated Financial Statements—(Continued)

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

were not material during the years ended December 31, 2009 and 2008. Management continues to monitor the performance of the invested collateral and work closely with the trustees to limit any potential losses.

In the fourth quarter of 2008, Exelon decided to end its participation in the securities lending program and chose to initiate a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to the absence of liquidity in the market. As part of its withdrawal plan and in order to minimize losses, Exelon temporarily increased its securities on loan during 2009. This temporary increase does not change Exelon’s intent to end its participation in the securities lending program. Currently, the weighted average maturity of the securities within the collateral funds is approximately 4 months. The fair value of securities on loan was approximately $356 million and $269 million at December 31, 2009 and 2008, respectively. The fair value of the cash and non-cash collateral received for these loaned securities was $365 million at December 31, 2009 and $274 million at December 31, 2008. A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trusts and the trustees in their capacity as security agents.

Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2009. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2009, there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets.

282

Combined Notes to Consolidated Financial Statements—(Continued)

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

Fair Value Measurements

The following table presents Exelon’s pension and other postretirement benefit plan assets measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009:


As of December 31, 2009 (In millions) ^(a) (f)	Level 1		Level 2		Level 3		Total
Pension Plan Assets
Cash equivalents	$	37	$	—	$	—	$	37
Equity securities		1,357		—		—		1,357	^(b)
Commingled funds		515		3,641		450		4,606	^(c)
Fixed Income
Debt securities issued by the U.S. Treasury and other								—	^(d)
U.S. government corporations and agencies		140		23		—		163	^(d)
Debt securities issued by states of the United States and by political subdivisions of the states		—		11		—		11	^(d)
Corporate debt securities		—		245		—		245	^(d)
Federal agency mortgage-backed securities		—		825		—		825	^(e)
Non-federal agency mortgage-backed securities		—		342		—		342	^(e)

Fixed Income subtotal		140		1,446		—		1,586

Real Estate		154		—		156		310

Pension Plan Assets subtotal	$	2,203	$	5,087	$	606	$	7,896

Other postretirement benefit plan assets
Cash equivalents		4		—		—		4
Equity securities		199		—		—		199	^(b)
Commingled funds		112		894		—		1,006	^(c)
Fixed Income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		14		2		—		16
Debt securities issued by states of the United States and by political subdivisions of the states		—		103		—		103	^(d)
Corporate debt securities		—		20		—		20	^(d)
Federal agency mortgage-backed securities		—		94		—		94	^(e)
Non-federal agency mortgage-backed securities		—		34		—		34	^(e)

Fixed Income subtotal		14		253		—		267

Real Estate		1		—		—		1

Postretirement benefit plan subtotal	$	330	$	1,147	$	—	$	1,477

Total pension and other postretirement benefit plan assets	$	2,533	$	6,234	$	606	$	9,373

(a)	See Note 7—Fair Value of Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)

The performance of equity portfolios is benchmarked against the Standard and Poor’s (S&P) 500 Index, Russell 2000 Index or the Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index. Excludes a $210 million payable for collateral on loaned securities in connection with the benefit plans’ participation in securities lending programs.

(c)

The benefit plans own commingled funds that invest in equity and fixed income securities, private equity, and real estate. The commingled funds that invest in equity securities seek to out-perform the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 2000 Index. The commingled funds that hold fixed income securities invest primarily in domestic investment grade securities. Including corporate, municipal, and U.S. Treasury securities. The commingled funds that hold private equity investments seek to track the Russell 2000 plus 300 basis points. The commingled funds that hold direct investments in real estate are diversified by geography and type of property. These funds are benchmarked to the National Council of Real Estate Investment Fiduciaries (NCREIF) index.

(d)	This category predominantly represents diverse issues of domestic, investment-grade fixed income securities. Excludes a $148 million payable for collateral on loaned securities in connection with the benefit plans’ participation in securities lending programs.

(e)

This category represents investments in federal agency, commercial and residential mortgage-backed securities that seek to out-perform the Barclays Capital Aggregate Index. Excludes a $7 million payable for collateral on loaned securities in connection with the benefit plans’ participation in securities lending programs.

(f)	The total fair value of pension and other postretirement benefit plan assets excludes $20 million of interest and dividends receivable and $40 million related to pending sales transactions.

283

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans during the year ended December 31, 2009:


(in millions)	Commingled funds in private equity Investments			Commingled funds in direct real estate			Total
Pension Assets
Balance as of January 1, 2009	$	808		$	232		$	1,040
Actual return on plan assets:
Relating to assets still held at the reporting date		57			(88	)		(31	)
Relating to assets sold during the period		35			—			35
Purchases, sales and settlements		136			12			148
Transfers into (out of) Level 3		(586	)		—			(586	)

Balance as of December 31, 2009	$	450		$	156		$	606

Other Postretirement Benefits
Balance as of January 1, 2009	$	53		$	—		$	53
Relating to assets sold during the period		23			—			23
Transfers into (out of) Level 3		(76	)		—			(76	)

Balance as of December 31, 2009	$	—		$	—		$	—

Valuation Techniques Used to Determine Fair Value

Cash equivalents. Investments with maturities of three months or less when purchased, including certain short-term fixed-income securities, are considered cash equivalents and are included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

Equity securities. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Preferred and common corporate stocks are valued based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on exchanges which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

Commingled funds. Commingled funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of the majority of commingled funds are not publically quoted and must trade through a broker. For equity and fixed-income commingled fund traded through a broker, the fund administrator values the fund using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized in Level 2. Equity and fixed-income funds with publically quoted prices have been categorized in Level 1. Private equity commingled funds are generally partnerships in which a benefit plan is a limited partner. These partnerships generate capital returns through investing in enterprises such as other limited partnerships or other pooled investment vehicles which, in turn, make equity-oriented investments in venture capital companies. Private equity commingled funds are valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods. Since these valuation inputs are not highly observable, private equity funds have been categorized as Level 3.

284

Combined Notes to Consolidated Financial Statements—(Continued)

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

Fixed-income securities. For fixed income securities, multiple prices and price types are obtained from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized in Level 1 because they trade in highly-liquid and transparent markets. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. To draw parallels from the trading and quoting of fixed income securities with similar features, pricing services consider various characteristics including the issuer, maturity, purpose of loan, collateral attributes, prepayment speeds, interest rates and credit ratings in order to properly value these securities.

Real Estate. Real estate investment trusts are valued daily based on quoted prices in active markets and are categorized in Level 1. Real estate commingled funds are funds with a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, real estate investments have been categorized as Level 3 investments.

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
2009	$	70	$	36	$	20	$	8
2008		66		33		19		7
2007		63		30		18		6

14. Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)

The Registrants provide severance and health and welfare benefits to terminated employees primarily based upon each individual employee’s years of service and compensation level. The Registrants accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

285

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents total severance benefits costs, recorded as operating and maintenance expense for the year ended December 31, 2009:


Severance Benefits Expense ^(a)(b)	Generation		ComEd		PECO		Other		Exelon
Corporate restructuring—2009	$	11	$	19	$	3	$	1	$	34
Plant retirements—2009 ^(c)		7		—		—		—		7

Total severance benefits expense	$	18	$	19	$	3	$	1	$	41

(a)	The amounts above include $7 million, $4 million, and $2 million at Generation, ComEd and PECO, respectively, for amounts billed through intercompany allocations for the year ended December 31, 2009.

(b)

The severance benefits costs include $1 million of stock compensation expense collectively at Generation and ComEd for which the obligation is recorded in equity for the year ended December 31, 2009, respectively. Severance benefits also include $4 million and $2 million at Exelon and ComEd, respectively, of contractual termination benefits expense for which the obligation is recorded in other postretirement benefits.

(c)	Severance-related expenses associated with plant retirements are described below.

Corporate restructuring (Exelon, Generation, ComEd and PECO). On June 18, 2009, Exelon announced a restructured senior executive team and major spending cuts, including the elimination of approximately 500 employee positions. Exelon eliminated approximately 400 corporate support positions, mostly located at corporate headquarters, and 100 management level positions at ComEd, the majority of which was completed by September 30, 2009. These actions were in response to the continuing economic challenges confronting all parts of Exelon’s business and industry especially in light of the commodity-driven nature of Generation’s markets, necessitating continued focus on cost management through enhanced efficiency and productivity.

Exelon recorded a pre-tax charge for estimated salary continuance and health and welfare severance benefits of $40 million in June 2009 as a result of the planned job reductions. Subsequent to June, Exelon recorded a net pre-tax credit of approximately $6 million, which included a $10 million reduction in estimated salary continuance and health and welfare severance benefits, offset by $4 million of expense for contractual termination benefits. Cash payments under the plan began in July 2009 and will continue through 2010. Substantially all cash payments are expected to be made by the end of 2010 or early 2011 resulting in the completion of the corporate restructuring plan.

The following table presents the activity of severance obligations for the corporate restructuring from January 1, 2009 through December 31, 2009, excluding obligations recorded in equity:


Severance Benefits Obligation	Generation			ComEd			PECO			Other			Exelon
Balance at January 1, 2009	$	—		$	—		$	—		$	—		$	—
Severance charges recorded		7			12			2			18			39
Cash payments		(1	)		(5	)		—			(4	)		(10	)
Other adjustments		(3	)		—			(1	)		(6	)		(10	)

Balance at December 31, 2009	$	3		$	7		$	1		$	8		$	19

Plant Retirements (Exelon and Generation). On December 2, 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station (Cromby) Unit 1 and Unit 2 and Eddystone Generating Station (Eddystone) Unit 1 and Unit 2. In connection with these retirements, Exelon will eliminate approximately 280 employee positions, the majority of which are

286

Combined Notes to Consolidated Financial Statements—(Continued)

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

located at the units to be retired. These actions were in response to the economic outlook related to the continued operation of these four units. Total expected costs for Generation related to the announced retirements is $40 million, which includes $18 million for estimated salary continuance and health and welfare severance benefits, a $17 million write down of inventory and $5 million of shut down costs. Additionally, approximately $218 million of accelerated depreciation expense will be recorded ratably until the plant shutdown date. During the year ended December 31, 2009, Generation recorded a pre-tax charge of $24 million related to the announced retirements, which included a $7 million charge for estimated salary continuance and health and welfare severance benefits, and $17 million of expense for the write down of inventory recorded within operating and maintenance expense in Exelon and Generation’s Consolidated Statements of Operations. Additionally, Generation recorded $32 million of accelerated depreciation expense within depreciation and amortization expense in Exelon’s and Generation’s Consolidated Statements of Operations.

The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements in December of 2009 from January 1, 2009 through December 31, 2009, excluding obligations recorded in equity:


Severance Benefits Obligation	Exelon and Generation
Balance at January 1, 2009	$	—
Severance charges recorded		7
Cash payments		—

Balance at December 31, 2009	$	7

On January 5, 2010, PJM notified Exelon that based upon its preliminary analysis, the retirement of one or more of the Cromby and Eddystone units may result in reliability impacts to the transmission system. On February 1, 2010, Generation notified PJM that to the extent the retirement of these units results in reliability impacts, Generation would continue operations beyond its desired deactivation date during the period of construction of the necessary transmission upgrades, provided that Exelon receives the required environmental permits and adequate cost-based compensation. Upon determination of which, if any, units continue to operate beyond May 31, 2011, Generation will reevaluate the appropriate depreciation useful lives for the impacted units at the time of and based on final operating and cost recovery arrangements made with PJM.

15. Preferred Securities (Exelon, ComEd and PECO)

At December 31, 2009 and 2008, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.

Preferred and Preference Securities of Subsidiaries

At December 31, 2009 and 2008, ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which were outstanding.

287

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2009 and 2008, PECO cumulative preferred securities, no par value, consisted of 15,000,000 shares authorized and the outstanding amounts set forth below. Shares of preferred securities have full voting rights, including the right to cumulate votes in the election of directors.


	Redemption Price ^(a)		December 31,
			2009	2008	2009		2008
			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 securities			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, Generation, ComEd and PECO)

At December 31, 2009 and 2008, Exelon’s common stock without par value consisted of 2,000,000,000 shares authorized and 659,798,515 and 658,154,642 shares outstanding, respectively. At December 31, 2009 and 2008, 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, 2009 and 2008, PECO’s common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding.

ComEd had 75,294 and 75,410 warrants outstanding to purchase ComEd common stock as of December 31, 2009 and 2008, respectively. 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, 2009 and 2008, 25,098 and 25,137 shares of common stock, respectively, were reserved for the conversion of warrants.

Share Repurchases

Share Repurchase Programs. 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 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 2004 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. During 2008, 6.6 million shares of common stock were purchased under this share repurchase program for $500 million.

On August 31 and December 19, 2007, Exelon’s Board of Directors approved a share repurchase program for up to $1.25 billion and $500 million of Exelon’s outstanding common stock, respectively. In 2007, Exelon entered into agreements to repurchase a total of $1.25 billion of Exelon’s common

288

Combined Notes to Consolidated Financial Statements—(Continued)

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

shares under the first accelerated share repurchase (ASR) program, and 2008, Exelon entered into an agreement to repurchase a total of $500 million of Exelon’s common shares under the second ASR program. Exelon accounted for each ASR program as two distinct transactions, as shares of common stock acquired in a treasury stock transaction and as a forward contract indexed to Exelon’s own common stock. The ASR agreements include a pricing collar, which establishes a minimum and maximum number of shares that can be repurchased. In September 2007 and February 2008. Exelon received the minimum number of shares, as determined by each of the ASR agreements, which amounted to 15.1 million shares and 5.8 million shares, respectively. These initial shares were recorded as treasury stock, at cost, for $1.17 billion and $436 million in September 2007 and February 2008, respectively.

The forward contract issued in September 2007 was settled in February 2008 when Exelon received 525,666 shares valued at $42 million. The ultimate settlement of this forward contract was based on changes in the price of Exelon’s common stock from September 24, 2007 through the date of settlement. The forward contract issued in February 2008 was settled in May 2008 when Exelon received 260,086 shares valued at $22 million. The ultimate settlement of this forward contract was based on changes in the price of Exelon’s common stock from February 29, 2008 through the date of settlement.

In the third quarter of 2008, Exelon’s board of directors approved a share repurchase program for up to $1.5 billion of Exelon’s outstanding common stock. Subsequently, Exelon management determined to defer indefinitely any share repurchases. This decision was made in light of a variety of factors, including: developments affecting the world economy and commodity markets, including those for electricity and gas; the continued uncertainty in capital and credit markets and the potential impact of those events on Exelon’s future cash needs; projected cash needs to support investment in the business, including maintenance capital and nuclear uprates; and value-added growth opportunities.

Under the share repurchase programs, 34.8 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of December 31, 2009. During 2009, Exelon had no common stock repurchases.

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, stock options and restricted stock units. At December 31, 2009, there were approximately 23 million shares authorized for issuance under the LTIP. During the years ended December 31, 2009, 2008 and 2007, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

As the LTIP sponsor, Exelon is the sole issuer of all stock-based compensation awards. All awards are recorded as equity or a liability in Exelon’s Consolidated Balance Sheets. The stock-based compensation expense specifically attributable to the employees of Generation, ComEd and PECO is directly recorded to operating and maintenance expense within each of their respective Consolidated Statements of Operations. Stock-based compensation expense attributable to BSC employees is allocated to the Registrants using a cost-causative allocation method.

289

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
Components of Stock-Based Compensation Expense	2009			2008			2007
Performance shares	$	31		$	28		$	76
Stock options		20			24			34
Restricted stock units		26			20			13
Other stock-based awards		4			4			2

Total stock-based compensation included in operating and maintenance expense		81			76			125

Income tax benefit		(32	)		(29	)		(48	)

Total after-tax stock-based compensation expense	$	49		$	47		$	77

The following table presents stock-based compensation expense (pre-tax) during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
Subsidiaries	2009		2008		2007
Generation	$	38	$	38	$	47
ComEd		4		4		8
PECO		6		6		5
BSC ^(a)		33		28		65

Total	$	81	$	76	$	125

(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

There were no significant stock-based compensation costs capitalized during the years ended December 31, 2009, 2008 and 2007.

290

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The tax deductions in excess of the benefits recorded throughout the requisite service period are recorded to common stock and are included in other financing activities within Exelon’s Consolidated Statements of Cash Flows. The following table presents information regarding Exelon’s tax benefits during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
	2009		2008		2007
Realized tax benefit when exercised/distributed:
Stock options	$	6	$	59	$	93
Restricted stock units		7		4		7
Performance share awards		19		27		28
Stock deferral plan		1		10		25
Excess tax benefits included in other financing activities of Exelon’s Consolidated Statements of Cash Flows:
Stock options		4		51		77
Restricted stock units		—		1		4
Performance share awards		—		2		1
Stock deferral plan		—		6		15

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock are granted under the LTIP. 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 LTIP generally become exercisable upon a specified vesting date. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant.

The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.

Exelon grants most of its stock options in the first quarter of each year. Stock options granted during the remaining quarters of 2009, 2008 and 2007 were not significant.

291

Combined Notes to Consolidated Financial Statements—(Continued)

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

The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
	2009			2008			2007
Dividend yield		3.72	%		2.73	%		2.94	%
Expected volatility		36.70	%		29.30	%		22.00	%
Risk-free interest rate		2.01	%		3.17	%		4.71	%
Expected life (years)		6.25			6.25			6.25
Weighted average grant date fair value	$	14.43		$	18.36		$	13.05

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 year. Expected volatility is based on implied volatilities of traded stock options in Exelon’s common stock and historical volatility 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. For each year presented, the expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimate of expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.

The following table presents information with respect to stock option activity during the year ended December 31, 2009:


	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2008	11,341,728		$	45.17
Options granted	1,180,280			56.39
Options exercised	(686,059	)		29.29
Options forfeited	(213,510	)		60.71
Options expired	(184,898	)		36.95

Balance of shares outstanding at December 31, 2009	11,437,541		$	47.12	5.42	$	83

Exercisable at December 31, 2009 ^(a)	9,888,686		$	45.00	5.05	$	83

(a)	Includes stock options issued to retirement eligible employees.

292

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table summarizes additional information regarding stock options exercised during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
Stock Options Exercised	2009		2008		2007
Intrinsic value ^(a)	$	15	$	147	$	231
Cash received for exercise price		20		108		186

(a)	The difference between the market value on the date of exercise and the strike price.

The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2009:


	Shares		Weighted Average Exercise Price (per share)
Nonvested at December 31, 2008 ^(a)	2,951,737		$	56.42
Granted ^(b)	1,180,280			56.39
Vested ^(b)	(2,369,652	)		53.23
Forfeited	(213,510	)		60.71

Nonvested at December 31, 2009 ^(a)	1,548,855		$	60.69

(a)	Excludes 1,213,909 and 953,175 of stock options issued to retirement-eligible employees at December 31, 2009 and December 31, 2008, respectively, as they are fully vested.

(b)	Includes 492,100 of stock options issued to retirement eligible employees that vested immediately on the date of grant.

As of December 31, 2009, $9 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 2.53 years.

Restricted Stock Units

Exelon grants restricted stock units under the LTIP. The majority of Exelon’s restricted stock units will be settled in common stock. In accordance with the authoritative guidance for share-based payments, the cost of services received from employees in exchange for the issuance of restricted stock units to be settled in stock is required to be measured based on the grant date fair value of the restricted stock unit issued. On a very limited basis, Exelon has granted restricted stock units to certain ComEd executives that will be settled in cash. The obligations related to these restricted stock units have been classified as liabilities on Exelon’s Consolidated Balance Sheets and are remeasured each reporting period throughout the requisite service period.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted if necessary.

293

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2009:


	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2008 ^(a)	899,510		$	64.26
Granted	517,569			56.08
Vested	(268,812	)		55.31
Forfeited	(75,370	)		62.96
Undistributed vested awards ^(b)	(144,955	)		58.45

Nonvested at December 31, 2009 ^(a)	927,942		$	63.30

(a)	Excludes 211,246 and 118,948 of restricted stock units issued to retirement-eligible employees at December 31, 2009 and December 31, 2008, respectively, as they are fully vested.

(b)	Represents restricted stock units granted to retirement-eligible participants in 2009.

The weighted average grant date fair value of restricted stock units granted during the years ended December 31, 2009, 2008 and 2007 was $56.08, $74.83 and $63.89, respectively. As of December 31, 2009 and 2008, Exelon had obligations related to outstanding restricted stock units not yet settled of $42 million and $33 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. In addition, Exelon had obligations related to outstanding restricted stock units that will be settled in cash of $1 million at December 31, 2009 and 2008, which are included in deferred credits and other liabilities in Exelon’s Consolidated Balance Sheets. During the years ended December 31, 2009, 2008 and 2007, Exelon settled restricted stock units with fair value totaling $17 million, $10 million and $18 million, respectively. As of December 31, 2009, $27 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.23 years.

Performance Share Awards

Exelon grants performance share awards under the LTIP. The number of performance shares granted is determined based on the performance of Exelon’s common stock relative to certain stock market indices during the three-year period through the end of the year of grant. These performance share awards generally vest and settle over a three-year period. The holders of performance share awards receive shares of common stock and/or cash annually during the vesting period. Participants are eligible for partial or full distributions in cash if they meet certain stock ownership requirements.

Performance share awards to be settled in stock are recorded as common stock within the Consolidated Balance Sheets and are recorded at fair value at the date of grant. The grant date fair value of equity classified performance share awards granted during the year ended December 31, 2009 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. Volatility for Exelon and all comparable companies is based on historical volatility over one year using daily stock price observation. Performance share awards expected to be settled in cash are recorded as liabilities within the Consolidated Balance Sheets. The grant date fair value of liability classified performance share awards granted during the year ended December 31, 2009 was based on historical data for the previous two plan years and

294

Combined Notes to Consolidated Financial Statements—(Continued)

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

actual results for the current plan year. The liabilities are remeasured each reporting period throughout the requisite service period and as a result, the compensation costs for cash-settled awards are subject to volatility.

For non retirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method, a method in which the compensation cost is recognized over the requisite service period for each separately vesting tranche of the award as though the award were multiple awards. For performance shares granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period which is the year of grant.

The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2009:


	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2008 ^(a)	924,373		$	66.47
Granted	475,972			57.34
Vested	(478,589	)		64.24
Forfeited	(25,536	)		66.15
Undistributed vested awards ^(b)	(265,962	)		59.58

Nonvested at December 31, 2009 ^(a)	630,258		$	64.20

(a)	Excludes 551,558 and 640,453 of performance share awards issued to retirement-eligible employees at December 31, 2009 and December 31, 2008, respectively, as they are fully vested.

(b)	Represents performance share awards granted to retirement-eligible participants in 2009.

The weighted average grant date fair value of performance share awards granted during the years ended December 31, 2009, 2008 and 2007 was $57.34, $72.89 and $59.94, respectively. During the years ended December 31, 2009, 2008 and 2007, Exelon settled performance shares with a fair value totaling $47 million, $69 million and $65 million, respectively, of which $30 million, $44 million and $39 million was paid in cash, respectively. As of December 31, 2009, $10 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.72 years.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:


	As of December 31,
Obligation Related to Outstanding Performance Share Awards	2009		2008
Current liabilities ^(a)	$	20	$	28
Deferred credits and other liabilities ^(b)		14		21
Common stock		26		26

Total	$	60	$	75

(a)	Represents the current liability related to performance share awards expected to be settled in cash.

(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

295

Combined Notes to Consolidated Financial Statements—(Continued)

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

17. Earnings Per Share and Equity (Exelon)

Earnings per Share

Diluted earnings per share is 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, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:


	2009		2008		2007
Income from continuing operations	$	2,706	$	2,717	$	2,726
Income from discontinued operations		1		20		10

Net income	$	2,707	$	2,737	$	2,736

Average common shares outstanding—basic		659		658		670
Assumed exercise and/or distributions of stock-based awards		3		4		6

Average common shares outstanding—diluted		662		662		676

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 5 million in 2009 and less than 1 million in 2008 and 2007.

18. Commitments and Contingencies (Exelon, Generation, ComEd and PECO)

Nuclear Insurance

The Price-Anderson Act was enacted to limit the liability of nuclear reactor owners for claims that could arise from a single incident at any of the U.S. licensed nuclear facilities and to ensure the availability of funds for claims arising in the event of an incident. As of December 31, 2009, the current liability limit per incident was $12.6 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 maintains a primary level of financial protection by carrying the maximum available amount of nuclear liability insurance for claims that could arise in the event of an incident. As of January 1, 2010, the required amount of nuclear liability insurance is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a secondary financial protection pool by the operators of all U.S. licensed reactors (currently 104 reactors) resulting in an additional $12.2 billion in funds available for claims. Participation in the financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of insurance coverage. Under the Price-Anderson Act, the maximum assessment, in the event of an incident for each nuclear operator per reactor per incident (including a 5% surcharge) is $117.5 million, payable at no more than $17.5 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.0 billion. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act, as amended, requires an inflation adjustment be made at least once each 5 years. The last inflation adjustment was effective October 29, 2008.

Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to

296

Combined Notes to Consolidated Financial Statements—(Continued)

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

accidents or acts of terrorism. Generation’s current limit for this coverage is $2.1 billion (except for Zion, which is $100 million). For property limits in excess of the first $1.25 billion of that limit, Generation participates in an $850 million single limit blanket policy shared by all the Generation operating nuclear sites and the Salem and Hope Creek nuclear sites. This blanket limit is not subject to automatic reinstatement in the event of a loss. 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 $163 million per year for losses incurred at any plant insured by the insurance company (the retrospective premium obligation). 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 amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007. The Terrorism Risk Insurance Act expires on December 31, 2014.

Additionally, NEIL provides replacement power cost insurance in the event of a major accidental outage at an insured nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Generation’s maximum share of any assessment is $44 million per year (the retrospective premium obligation). NEIL may require financial assurance of the ability to satisfy the obligation to pay this assessment. 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 not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act of 2002, as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007, as described above.

Effective April 1, 2009, NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. The current aggregate annual retrospective premium obligation for Generation is $207 million.

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 policy.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.

Energy Commitments

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation maintains a net positive supply of energy and capacity, through ownership of generation assets and

297

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 power generation of specific generation plants and/or are dispatchable in nature. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. Generation primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Generation also uses financial contracts to manage the risk surrounding trading for profit activities.

Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators. Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Generation provides delivery of its energy to these customers through rights for firm transmission.

At December 31, 2009, Generation’s short- and 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 Purchases ^(b)		Power Only Sales		Transmission Rights Purchases ^(c)
2010	$	305	$	91	$	1,307	$	10
2011		291		49		1,046		9
2012		274		22		568		9
2013		151		—		238		6
2014		145		—		120		—
Thereafter		1,105		—		761		—

Total	$	2,271	$	162	$	4,040	$	34

(a)

(b)	Excludes renewable energy PPA contracts that are contingent in nature.

(c)	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.

On April 4, 2007, Generation agreed to sell its rights to 942 MW of capacity, energy, and ancillary services supplied from its existing long-term contract with Tenaska Georgia Partners, LP through a tolling agreement with Georgia Power, a subsidiary of Southern Company, commencing June 1, 2010 and lasting for 20 years. The transaction was approved by the Georgia Public Service Commission (GPSC) in October of 2007. Exelon and Generation recognized a non-cash after-tax loss of approximately $72 million during the fourth quarter of 2007, which is included in purchased power on Exelon’s and Generation’s Consolidated Statements of Operations. The transaction provides Generation with approximately $43 million in annual revenue in the form of capacity payments over the term of the tolling agreement.

On October 15, 2007, Generation entered into an agreement (Termination Agreement) with State Line Energy, L.L.C. (State Line), an indirect wholly owned subsidiary of Dominion Resources Inc., to terminate the PPA dated as of April 17, 1996 (as amended, the State Line PPA) between State Line

298

Combined Notes to Consolidated Financial Statements—(Continued)

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

and Generation relating to the State Line generating facility in Hammond, Indiana. Under the State Line PPA, Generation controlled 515 MW of electric energy and capacity from the State Line facility. FERC approved the Termination Agreement on October 18, 2007. The conditions to the effectiveness of the Termination Agreement were subsequently satisfied and Generation recorded income of approximately $223 million in the fourth quarter of 2007, which is included in operating revenues on Exelon’s and Generation’s Consolidated Statements of Operations.

Pursuant to a PPA with Public Service Company of Oklahoma, a subsidiary of American Electric Power, dated as of April 17, 2009, Generation agreed to sell its rights to up to 520 MW, or approximately two-thirds of the capacity, energy and ancillary services supplied under its existing long-term contract with Green Country Energy, LLC. The delivery of power under the PPA is to commence June 1, 2012 and run through February 28, 2022.

On December 17, 2009, Generation entered into a PPA with Entergy Texas, Inc. (ETI) to sell 150 MWs through April 30, 2011 and 300 MWs thereafter of capacity and energy from the Frontier Generating Station located in Grimes County, Texas. The approximate ten year PPA is not included within the Net Capacity table above because it is contingent upon ETI waiving or obtaining regulatory approvals, which may occur after the commencement of the PPA on May 1, 2010.

ComEd purchases a portion of its expected energy requirements through various SFCs resulting from ICC-approved auctions and a competitive procurement process designed by the IPA and approved by the ICC. On January 7, 2009, the ICC approved the IPA’s plan for procurement of ComEd’s expected energy requirements from June 2009 through May 2010 which includes purchases through the spot market hedged by the financial swap contract with Generation, existing SFCs, and standard products purchased as a result of the 2009 RFP process completed in May 2009. On December 28, 2009, the ICC approved the IPA’s latest procurement plan which will result in additional contracts for standard products in the 2010 RFP process expected to be completed in the first half of 2010. See Note 2—Regulatory Issues for further information.

PECO has a long-term PPA with Generation under which PECO obtains 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 restructuring settlement mandated by the Competition Act. Subsequent to 2010, PECO expects to procure all of its electric supply from market sources, which will include Generation.

During 2009, PECO entered into procurement contracts to enable PECO to meet a portion of its customers’ electric supply requirements for 2011, 2012 and 2013.

ComEd and PECO are also subject to requirements established by the Illinois Settlement Legislation and the AEPS Act, respectively, related to alternative energy resources. See Note 2—Regulatory Issues for additional information relating to electric generation procurement and alternative energy resources.

299

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd’s and PECO’s electric supply procurement, REC and AEC purchase commitments as of December 31, 2009 are as follows :


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
ComEd
Electric supply procurement	$	645	$	615	$	30	$	—	$	—
RECs	$	8	$	8	$	—	$	—	$	—
PECO
Electric supply procurement	$	938	$	—	$	888	$	50	$	—
AECs	$	37	$	9	$	19	$	9	$	—

Fuel Purchase Obligations

In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation (and with respect to coal, commitments to sell coal) and PECO has commitments to purchase natural gas, related transportation, storage capacity and services. As of December 31, 2009, these net commitments were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Generation	$	10,105	$	1,085	$	2,162	$	1,950	$	4,908
PECO		574		152		173		123		126

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	297	$	289	$	8	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(b)		14		11		3		—		—
Surety bonds ^(c)		76		7		—		—		69
Performance guarantees ^(d)		96		—		—		95		1
Energy marketing contract guarantees ^(e)		218		193		25		—		—
Nuclear insurance premiums ^(f)		2,204		—		—		—		2,204
Lease guarantees ^(g)		125		—		—		15		110
2007 City of Chicago Settlement ^(h)		6		3		3		—		—
Midwest Generation Capacity Reservation Agreement guarantee ⁽ⁱ⁾		10		4		6		—		—
Rate relief commitments—Settlement Legislation ^(j)		25		25		—		—		—

Total commercial commitments	$	3,071	$	532	$	45	$	110	$	2,384

(a)

300

Combined Notes to Consolidated Financial Statements—(Continued)

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

(b)

(c)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(d)	Performance guarantees—Guarantees issued to ensure performance 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 as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

(g)	Lease guarantees—Guarantees issued to ensure payments on building leases.

(h)	2007 City of Chicago Settlement—In December 2007, ComEd entered into an agreement with the City of Chicago. Under the terms of the agreement, ComEd will pay $55 million over six years, of which $8 million, $18 million and $23 million was paid in December 2009, 2008 and 2007, respectively.

(i)

(j)	See Note 3—Regulatory Issues for additional detail related to Generation’s and ComEd’s rate relief commitments.

Generation’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a) (b)	$	172	$	172	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(c)		11		11		—		—		—
Surety bonds ^(d)		3		—		—		—		3
Performance guarantees ^(e)		96		—		—		95		1
Energy marketing contract guarantees ^(f)		218		193		25		—		—
Nuclear insurance premiums ^(g)		2,204		—		—		—		2,204
Rate relief commitments—Settlement Legislation ^(h)		24		24		—		—		—

Total commercial commitments	$	2,728	$	400	$	25	$	95	$	2,208

(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 $8 million have been issued to provide support for certain letters of credit as required by third parties.

(b)	The amount includes letters of credit that are posted to ComEd related to the 2006 Illinois procurement auction.

(c)

(d)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(e)	Performance guarantees—Guarantees issued to ensure performance under specific contracts.

(f)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts.

(g)

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 as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

(h)	See Note 2—Regulatory Issues for additional detail related to Generation’s rate relief commitments.

301

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	80	$	80	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(b)		3		—		3		—		—
2007 City of Chicago Settlement ^(c)		6		3		3		—		—
Midwest Generation Capacity Reservation Agreement guarantee ^(d)		10		4		6		—		—
Surety bonds ^(e)		2		2		—		—		—
Rate relief commitments—Settlement Legislation ^(f)		1		1		—		—		—

Total commercial commitments	$	102	$	90	$	12	$	—	$	—

(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)

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 $191 million is reflected in long-term debt in ComEd’s Consolidated Balance Sheet.

(c)	2007 City of Chicago Settlement—In December 2007, ComEd entered into an agreement with the City of Chicago. Under the terms of the agreement, ComEd will pay $55 million over six years, of which $8 million, $18 million and $23 million was paid in December 2009, 2008 and 2007, respectively.

(d)

(e)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(f)	See Note 2—Regulatory Issues for additional detail related to ComEd’s rate relief commitments.

PECO’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	39	$	32	$	7	$	—	$	—
Surety bonds ^(b)		3		3		—		—		—

Total commercial commitments	$	42	$	35	$	7	$	—	$	—

(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.

302

Combined Notes to Consolidated Financial Statements—(Continued)

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

Construction Commitments

Under their operating agreements with PJM, ComEd and PECO are committed to construct transmission facilities. ComEd and PECO will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd’s and PECO’s estimated commitments are as follows:


	Total		2010		2011-2012		2013-2014
ComEd	$	91	$	16	$	23	$	52
PECO		105		35		45		25

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2009 were:


	Exelon			Generation			ComEd ^(b)		PECO ^(b)
2010	$	67		$	27		$	17	$	15
2011		65			26			16		15
2012		65			26			16		15
2013		58			24			14		14
2014		53			24			12		13
Remaining years		358			298			20		1

Total minimum future lease payments	$	666	^(a)	$	425	^(a)	$	95	$	73

(a)	Excludes Generation’s PPAs and other capacity contracts that are accounted for as contingent operating lease payments.

(b)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd and PECO have excluded these payments from the Remaining years as such amounts would not be meaningful. ComEd’s and PECO’s annual obligation for these agreements, included in each of the years 2010 – 2014, was $2 million and $2 million, respectively.

The Registrants’ rental expense under operating leases was as follows:


	Exelon		Generation ^(a)		ComEd		PECO
2009	$	691	$	637	$	21	$	27
2008		867		817		23		27
2007		869		819		25		24

(a)

Includes Generation’s PPAs and other capacity contracts 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 Generation’s PPAs and other capacity contracts totaled $616 million, $787 million and $785 million during 2009, 2008 and 2007, respectively.

For information regarding capital lease obligations, see Note 9–Debt and Credit Agreements.

Indemnifications Related to 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 consummated the acquisition of Reservoir Capital Group’s 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy, Inc. (Dynegy).

303

Combined Notes to Consolidated Financial Statements—(Continued)

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

In connection with the sale, Generation recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. Any activity related to Sithe recorded in Exelon’s Consolidated Statement of Operations is recorded as discontinued operations. During 2008, Generation reduced its guarantee liabilities and recognized $38 million of income in discontinued operations related to the expiration of tax indemnifications. As of December 31, 2009, Generation had $6 million in guarantee liabilities remaining. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at December 31, 2009.

Indemnifications Related to Sale of TEG and TEP (Exelon and Generation)

On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guarantees the timely payment of TII’s obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII’s ownership interests. Generation would be required to perform in the event that TII does not pay any obligation covered by the guarantee that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guarantee is $95 million. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guarantee expired in part during 2008.

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 MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several PRPs which may be responsible for ultimate remediation of each location. Of the 42 sites identified by ComEd, the Illinois EPA or U.S. EPA have approved the cleanup of 11 sites and of the 27 sites identified by PECO, the PA DEP has approved the cleanup of 16 sites. Of the remaining sites identified by ComEd and PECO, 24 and 9 sites, respectively, are currently under 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 2021, 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), were parties to an interim agreement under which they cooperated in remediation activities at 38 former MGP sites for which ComEd or Nicor, or both, have responsibility. In January 2008, ComEd and Nicor executed a definitive written agreement on the allocation of costs for the MGP sites, which was approved by the ICC on June 9, 2009. The approval of the settlement by the ICC did not have an impact on ComEd’s cash flows or results of operations. ComEd’s accrual as of December 31, 2009 for these environmental liabilities reflects the cost allocations defined in the agreement. ComEd will continue to pass through to customers these environmental cleanup costs pursuant to a rider approved by the ICC as discussed below.

304

Combined Notes to Consolidated Financial Statements—(Continued)

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

Based on the final order received from the ICC, ComEd is recovering from customers a provision for environmental costs for the remediation of former MGP facility sites, including those incorporated in the Nicor Settlement, for which ComEd has recorded a regulatory asset. Based on the final order received from the PAPUC, PECO is currently recovering from customers a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset. The gas distribution rate settlement approved in 2008 authorized the recovery, on an annual basis, of $3.5 million for the remediation of PECO’s former MGP sites based on an 8-year estimated remaining duration of PECO’s MGP remediation program. See Note 19—Supplemental Financial Information for additional information regarding regulatory assets and liabilities.

During the third quarter of 2009, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by $9 million and $2 million, respectively. In January 2010, ComEd was notified by an MGP site owner of its intention to change the planned future use of its site. This change in the planned use of the site is expected to require additional costs for remediation. As a result, ComEd increased its reserve and regulatory asset for its share of the estimated increased remediation costs by an additional $22 million as of December 31, 2009.

As of December 31, 2009 and 2008, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other Deferred Credits and Other Liabilities within their Consolidated Balance Sheets:


December 31, 2009	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	175	$	149
Generation		17		—
ComEd		113		107
PECO		45		42

December 31, 2008	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	151	$	127
Generation		16		—
ComEd		89		83
PECO		46		44

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 U.S. 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 provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-

305

Combined Notes to Consolidated Financial Statements—(Continued)

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

cycle recirculating systems (e.g., cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, 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. The court found that with respect to a number of significant provisions of the rule the EPA 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 which were supported by the utility industry because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its location and operations. On July 9, 2007, the EPA formally suspended the Phase II rule. Until the EPA finalizes the rule on remand (which could take several years), the state permitting agencies will continue the current practice of applying their best professional judgment to address impingement and entrainment requirements at plant cooling water intake structures.

On April 14, 2008, the U.S. Supreme Court granted a petition filed by the industry parties on the issue of whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On April 1, 2009, the Supreme Court issued a ruling that the EPA has the discretion to use a cost-benefit analysis under Section 316(b) and reversed the decision of the U.S. Second Circuit Court of Appeals that had invalidated the use of a cost-benefit test. The EPA will now take up consideration of the rule on remand and take further action consistent with the opinions of the Supreme Court and the Court of Appeals, including whether to exercise its discretion to retain or modify the cost-benefit rule as it appeared in the initial regulation. It is expected that the EPA will issue a proposed rule on remand in 2010. The Courts’ opinions have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements.

In a draft permit issued on July 19, 2005, as part of the pending NPDES permit renewal process for Oyster Creek, the NJDEP preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for Section 316(b) compliance at Oyster Creek. In light of the suspension of the Phase II rule by the EPA, the NJDEP advised Generation that it will issue a new draft permit, and reiterated its preference for cooling towers as the best technology available in the exercise of its best professional judgment. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would require the installation of cooling towers within seven years after the effective date of the permit. Oyster Creek will continue to operate under its current permit, issued in 1994, until the draft permit is finalized after a period of public comment. Generation believes the public comment period and regulatory process could take up to two years before a final permit is issued. Should the permit be issued in its current form, Generation estimates it would be required to have cooling towers in operation by 2019.

Generation estimates that the cost to retrofit Oyster Creek with closed cycle cooling towers would be approximately $700 million to $800 million. This cost estimate includes construction materials and labor, lost capacity and energy revenue during construction, and other ongoing incremental operating and maintenance costs. Generation believes that these additional costs would call into question the economic viability of operating Oyster Creek until the expiration of its current operating license in 2029, and Generation would close Oyster Creek if either the final Section 316(b) regulations or NJDEP

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Combined Notes to Consolidated Financial Statements—(Continued)

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

requirements have performance standards that require the installation of cooling towers. Closure of Oyster Creek could result in reliability issues associated with the transmission system. Generation believes the period allowed for compliance will be sufficient to address any transmission reliability issues before operations at Oyster Creek are shut down. If PJM requires the plant to operate under a “reliability-must-run” order, Generation would be allowed full recovery of its costs to operate until the transmission issues are resolved.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in July 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 the final permit or 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.

Generation will contest the requirement to install cooling towers throughout the administrative permitting process and is optimistic that any final regulations or permits will not require closed-cycle cooling at Oyster Creek or Salem. In addition, the economic viability of Generation’s other power generation facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Given the uncertainties associated with these proceedings and the time required for their resolution, Generation cannot predict the eventual outcome of the proceedings or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its generating facilities and its future results of operations, cash flows and financial position.

Cotter Corporation. The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is $37 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve excavation of the radiological contamination. An excavation remedy would be significantly more expensive than the previously selected additional cover remedy. Generation cannot determine at this time whether the alternative remedy will be required, and if it is, Generation’s share of the cost for such alternative remedy.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Air. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO₂ and NO_x. The Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA may remedy “CAIR’s flaws” in accordance with the Court’s July 11, 2008 opinion. This decision allows the CAIR to remain in effect until it is replaced by a rule consistent with the Court’s July 11 opinion. The U.S. EPA is expected to issue a new proposed CAIR rulemaking in early 2010.

On March 5, 2009, the D.C. Circuit Court remanded Sierra Club and Environment North Carolina vs. EPA to the U.S. EPA for reconsideration of its denial of North Carolina’s Section 126 petition, originally filed in 2004, that requested that the U.S. EPA impose NO_x and SO₂ emission reduction requirements on various named upwind states (including Illinois and Pennsylvania) whose air emissions North Carolina contended were contributing significantly to nonattainment in North Carolina. The U.S. EPA has agreed to re-visit North Carolina’s Section 126 petition for potential rulemaking and could attempt to address North Carolina’s concerns as part of its CAIR revisions or via a separate rulemaking.

At this time, Exelon is unable to predict the exact approach that will be utilized by the U.S. EPA to revise its CAIR regulation, how long the current CAIR program will remain in effect, or what steps individual states may take in response to the CAIR situation. Due to the uncertainty as to any of the potential outcomes related to CAIR and North Carolina’s Section 126 petition, Exelon cannot estimate the effect of the decision on its operations and its future competitive position, results of operations, earnings, cash flows and financial position.

In March 2005, the U.S. EPA finalized the CAMR, which is a national program to cap mercury emissions from fossil-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. The D.C. Circuit Court later vacated the CAMR on the basis that the U.S. EPA had failed to properly de-list mercury as a hazardous air pollutant (HAP) under Section 112(c)(1) of the Clean Air Act. The result of this decision is that mercury emissions from electric generating stations are subject to the more stringent requirements of maximum achievable control technology applicable to hazardous air pollutants. On February 23, 2009, the U.S. Supreme Court declined to review the D.C. Circuit Court’s CAMR decision. The U.S. EPA is now expected to propose a new rulemaking, likely in the first quarter of 2010, to address HAP emissions from electric generation power plants. In addition to regulation at the national level, Exelon had been subject to more stringent mercury regulation enacted in 2006 at the state level in Pennsylvania (PA Mercury Rule). However, on January 30, 2009, the Commonwealth Court of Pennsylvania ruled that the PA Mercury Rule is unlawful and invalid and enjoined the state from continued implementation and enforcement of the rule. On December 23, 2009, the Supreme Court of Pennsylvania upheld the Commonwealth Court decision, and therefore mercury emissions are not regulated by the state. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Federal regulations are finalized by the U.S. EPA.

The EPA has announced that it will complete a review of the national ambient air quality standards by the end of 2011 for ozone (nitrogen oxide and volatile organic chemicals), particulate matter, carbon monoxide, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Notices and Finding of Violations Related to Electric Generation Stations. On August 6, 2007, ComEd received an NOV, addressed to it and Midwest Generation, LLC (Midwest Generation) from the U.S. EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the Federal Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since 1999. The U.S. EPA requested information related to the stations in 2003, and ComEd has been cooperating with the U.S. EPA since then. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act.

The generating stations that are the subject of the NOV are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of the sale agreement, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale.

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations with respect to its former generation business. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV, the costs that might be incurred or the amount of indemnity that may be available from Midwest Generation and EME; however, Exelon, Generation and ComEd have concluded that a loss is not probable or estimable and accordingly, have not recorded a reserve for the NOV.

On January 14, 2009, Generation received an NOV, addressed to it, the other owners of Keystone Generating Station (Keystone) and Reliant Energy Northeast Management Company (the operator of Keystone) from the U.S. EPA, alleging past and continuing violations of several provisions of the Federal Clean Air Act as a result of the modification and/or operation of Keystone, as well as two other stations currently owned and operated by Reliant Energy in which Generation has no ownership interest. Generation has been cooperating with the U.S. EPA since the time of requests for information in 2000, 2001 and 2007. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act. At this time, Exelon and Generation are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation; however, Exelon and Generation have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

On April 16, 2009, the U.S. EPA issued an NOV to ComEd and Dominion Resources Services, Inc. (Dominion) alleging past and continuing violations of several provisions of the Federal Clean Air Act as a result of the modification and/or operation of Kincaid electric generating station located in Illinois and State Line electric generating station located in Indiana. Kincaid was sold by ComEd in 1998 and State Line was sold by Commonwealth Edison of Indiana, a wholly owned subsidiary of ComEd, in 1997. Both stations are currently owned and operated by Dominion. The U.S. EPA requested information related to the stations in 2009, and ComEd has been cooperating with the U.S.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

EPA since the time of that request. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act.

Under the terms of the sales agreements for the Kincaid and State Line stations, each party agreed to indemnify the other for certain environmental activities, events, conditions or occurrences arising before and after the purchase of the stations; however, Exelon, Generation, and ComEd are unable at this time to determine how those provisions may apply to any liability or cost that may eventually arise out of the NOV or any resulting enforcement action.

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations related to ComEd’s former generation business, which would include any responsibility under the indemnification provisions contained in the sale agreements related to Kincaid and State Line stations. At this time, Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation or ComEd; however, Exelon, Generation and ComEd have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the international, Federal, regional and state levels.

International Climate Change Regulation. At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, the United States agreed to the non-binding Copenhagen Accord at the conclusion of the 15th Conference of the Parties under the UNFCCC. Under the Copenhagen Accord, the United States agreed to undertake a number of voluntary measures, including the establishment of a goal to reduce GHG emissions and contributions toward a fund to assist developing nations to address their GHG emissions. The next Conference of the Parties is scheduled for Mexico in late 2010.

Federal Climate Change Legislation and Regulation. Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.

Numerous bills have been introduced in Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal RPS. Exelon supports the enactment, through Federal legislation, of a cap-and-trade program for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over

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Combined Notes to Consolidated Financial Statements—(Continued)

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

the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable.

Federal climate change legislation is currently under consideration in the U.S. Congress. H.R. 2454, “The American Clean Energy and Security Act of 2009,” which Exelon supported, was approved by the U.S. House of Representatives on June 26, 2009 and would affect electric generation and electric and natural gas distribution companies. A key provision of H.R. 2454 is the establishment of mandatory, economy-wide GHG reduction targets and goals via a Federal emissions cap-and-trade program. The program would begin in 2012 and calls for a three percent reduction below 2005 levels in 2012, with the reduction requirement increasing to 17% below 2005 levels by 2020 and ultimately 83% below 2005 levels by 2050. The legislation also contains several energy efficiency and clean energy requirements. Of particular note for electric retail supply companies, there is a proposed requirement that 20% of electricity sold by retail suppliers be met by energy efficiency and renewable energy by 2020. The requirement begins to phase-in starting in 2012 at a six percent level and escalates every two years until it reaches 20% in 2020. On September 30, 2009, S. 1733, the Clean Energy Jobs and American Power Act, was introduced in the U.S. Senate. S.1733 sets forth a cap-and-trade program and contains other provisions to regulate GHGs that are similar to those contained in H.R. 2454, but does not yet provide the specific details regarding the allocation of allowances. It is uncertain when the Senate will take up consideration of S. 1733.

In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. In response to the decision, on July 11, 2008, the U.S. EPA issued an Advance Notice of Proposed Rulemaking to solicit public comments on legal and regulatory analyses and policy alternatives regarding GHG effects and regulation under the Clean Air Act. On December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and is expected to finalize regulations in March 2010. While such regulations would not specifically address stationary sources, such as a generating plant, it is the U.S. EPA’s position that the regulation of GHGs under the mobile source provisions of the Clean Air Act will trigger permitting requirements for stationary sources. Therefore, on September 30, 2009, the U.S. EPA issued proposed regulations for permitting for large stationary sources (greater than 25,000 tons per year of GHG emissions, on a CO₂ equivalent basis). Under the proposal, large stationary sources could be required to install Best Available Control Technology, to be determined on a case-by-case basis.

The issue of GHG regulation of stationary sources will likely be addressed either under the existing provisions of the Clean Air Act by U.S. EPA regulation, or by new and comprehensive Federal legislation. The Obama administration and the U.S. EPA have stated a preference for addressing the issue through Federal legislation. The extent to which GHG emissions will be regulated is currently unknown; however, potential regulation of GHG emissions from stationary sources could cause Exelon to incur material costs of compliance.

Pursuant to U.S. 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. The Keystone SO₂ scrubbers for Unit 1 and Unit 2 were placed in service September 25, 2009 and November 30, 2009, respectively. For the years ended

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Combined Notes to Consolidated Financial Statements—(Continued)

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

December 31, 2009, 2008 and 2007, total costs incurred, including capitalized interest, were $48 million, $71 million and $27 million, respectively. Exelon anticipates spending approximately $2 million in 2010 related to this project.

Regional and State Climate Change Legislation and Regulation. At a regional level, on November 15, 2007, six Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota, Wisconsin) signed the Midwestern Greenhouse Gas Accord (the Accord). Under the Accord, an inter-state work group was formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). In October 2009, the Governors decided to defer action on the regional GHG reduction initiatives pending resolution of federal legislation.

At the state level, the PCCA was signed into law in July 2008. The PCCA requires, among other things, that a Climate Change Advisory Committee be formed, that a report on the potential impact of climate change in Pennsylvania be developed, that the PA DEP develop a GHG inventory for Pennsylvania, that a voluntary GHG registry be identified, and that the PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. The Climate Change Advisory Committee issued its recommendations for an Action Plan on October 9, 2009 and they are currently being considered by the Pennsylvania legislature.

At this time, Exelon is unable to estimate the potential impacts of any future mandatory GHG legal or regulatory requirements on its businesses.

Litigation and Regulatory Matters

Exelon and Generation

Real Estate Tax Appeals. On January 19, 2010, Generation appealed the real estate tax assessment for the 2009 tax year concerning the value of its LaSalle Generating Station (LaSalle County, Illinois). The ultimate outcome of this matter is uncertain and could result in unfavorable or favorable impacts to the consolidated financial statements of Exelon and Generation. Generation has recorded the assessed real estate tax as of December 31, 2009.

Exelon and Generation

Asbestos Personal Injury Claims. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material. In the second quarter of 2008, Generation revised the period through which it estimates that claims will be presented from 2030 to 2050.

At December 31, 2009 and 2008, Generation had reserved approximately $49 million and $52 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2009, approximately $13 million of this amount related to 147 open claims presented to Generation, while the remaining $36 million of the reserve is for estimated future asbestos-related bodily injury claims

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Combined Notes to Consolidated Financial Statements—(Continued)

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

anticipated to arise through 2050 based on actuarial assumptions and analysis, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. During 2009, 2008 and 2007, the updates to this reserve, including the extension of future claims to be considered from 2030 to 2050, did not result in a material adjustment.

Exelon

Pension Claims. 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 does not comply with the ERISA. The plaintiff seeks compensatory relief from the Plan on behalf of participants who received lump sum distributions between 2001 and 2006 and injunctive relief with respect to future lump sum distributions. The District Court dismissed the lawsuit but allowed the plaintiff to file an administrative claim with the Plan with respect to the calculation of the portion of his lump sum benefit accrued under the Plan’s prior traditional formula. On July 2, 2009, the U.S. Court of Appeals for the Seventh Circuit affirmed the District Court’s ruling, and the plaintiff’s subsequent motion requesting rehearing of the case before the entire Seventh Circuit Court of Appeals was denied. On October 28, 2009, the plaintiff filed a petition requesting that the United States Supreme Court hear an appeal of the Seventh Circuit’s decision. In addition, on January 6, 2009, the plaintiff filed a complaint in the District Court challenging the Plan’s denial of his administrative claim, and on November 12, 2009 the Plan responded by filing a motion for summary judgment. The ultimate outcomes of these claims are uncertain and may have a material impact on Exelon’s results of operations, cash flows or financial position.

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 alleged 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 sought declaratory, equitable and monetary relief on behalf of the Savings Plan and participants, including alleged investment losses. On August 19, 2009, the plaintiffs in the Exelon case filed an amended complaint in the District Court, which again alleged that defendants breached fiduciary duties under ERISA by, among other things, permitting the Savings Plan to pay excessive fees and expenses for administrative services, but eliminated the claim for investment losses and the allegations regarding “revenue sharing.” On December 9, 2009, the District Court granted the defendants’ motion to dismiss the amended complaint and enter judgment in favor of the defendants. The plaintiffs have filed a notice of their intent to appeal the District Court’s dismissal of their claims to the U.S. Court of Appeals for the Seventh Circuit. The ultimate outcome of the savings plan claim is uncertain and may have a material impact on Exelon’s results of operations, cash flows or financial position.

Retiree Healthcare Benefits Grievance. In 2006, IBEW Local 15 filed a demand for arbitration of a grievance challenging certain changes implemented in 2004 to the healthcare coverage provided to retirees who were members of IBEW Local 15 during their employment with Exelon, Generation and

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Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd. Exelon then filed a lawsuit in the U.S. District Court for the Northern District of Illinois seeking a judicial determination that this grievance is not arbitrable because disputes regarding benefits provided to current retirees are not within the scope of the collective bargaining agreement. On December 3, 2007, the District Court ruled that, under the terms of the parties’ collective bargaining agreement, IBEW Local 15 could use the collective bargaining agreement’s grievance and arbitration procedure to challenge these changes with respect to retirees named in the grievance. On September 8, 2008, the U.S. Court of Appeals for the Seventh Circuit affirmed the decision of the District Court. A settlement agreement was reached between Exelon and IBEW Local 15 on February 19, 2009 that included certain prospective changes to the healthcare benefits provided to retirees who were members of IBEW Local 15 during their Exelon employment. These changes become effective at various times between May 1, 2009 and January 1, 2013 and resulted in withdrawal of the grievance. The settlement agreement will be treated as a plan amendment in the related welfare plan and reflected in the plan’s next measurement. The settlement agreement will not have a material impact on Exelon’s, Generation’s or ComEd’s results of operations, cash flows or financial position.

Exelon and ComEd

Reliability. On July 18, 2008, ComEd self-reported to ReliabilityFirst Corporation (RFC), its Regional Entity, that it failed to maintain vegetation clearance on a section of a transmission line, constituting a violation of a NERC reliability standard. ComEd is subject to potential fines for a violation of NERC reliability standards. ComEd and RFC reached a settlement for an immaterial amount. NERC approved the settlement agreement, and on October 23, 2009 FERC issued a Notice that it would not review the matter.

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.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 securities. At December 31, 2009, such capital was $2.7 billion and amounted to about 31 times the liquidating value of the outstanding preferred securities of $87 million. Additionally, PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.

Agreement Related to Sale of Accounts Receivable

PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable, which PECO accounted for as a sale as of December 31, 2009. Under new guidance effective January 1, 2010, this agreement will be accounted for as a secured borrowing. See Note 1—Significant Accounting Policies for additional information. PECO retains the servicing responsibility for the sold receivables and has recorded a servicing liability. The agreement terminates on September 16, 2010 unless extended in accordance with its terms. As of December 31, 2009, PECO is in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and will seek alternate financing. See Note 7—Fair Value of Financial Assets and Liabilities for additional information regarding the servicing liability.

Income Taxes

See Note 10—Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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, 2009, 2008 and 2007.


For the Year Ended December 31, 2009	Exelon		Generation			ComEd		PECO
Operating revenues ^(a)
Wholesale	$	5,469	$	8,905		$	—	$	26
Retail electric and gas		11,099		838	^(b)		5,220		5,049
Other		750		(40	)^(c)		554		236

Total operating revenues	$	17,318	$	9,703		$	5,774	$	5,311


For the Year Ended December 31, 2008	Exelon		Generation			ComEd		PECO
Operating revenues ^(a)
Wholesale	$	6,394	$	9,934		$	—	$	45
Retail electric and gas		11,816		979	^(b)		5,563		5,278
Other		649		(159	)^(c)		573		244

Total operating revenues	$	18,859	$	10,754		$	6,136	$	5,567


For the Year Ended December 31, 2007	Exelon		Generation			ComEd		PECO
Operating revenues ^(a)
Wholesale	$	6,550	$	9,970		$	58	$	61
Retail electric and gas		11,750		909	^(b)		5,543		5,300
Other		616		(130	)^(c)^(d)		503		252

Total operating revenues	$	18,916	$	10,749		$	6,104	$	5,613

(a)	Includes operating revenues from affiliates.

(b)	Generation’s retail electric and gas operating revenues consist solely of Exelon Energy Company, LLC.

(c)	Includes amounts recorded related to the Illinois Settlement.

(d)	Includes income associated with the termination of Generation’s PPA with State Line.

316

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	996	$	333	$	446	$	162
Regulatory assets ^(a)		838		—		48		790
Nuclear fuel ^(b)		558		558		—		—
ARO accretion ^(c)		209		207		1		—

Total depreciation, amortization and accretion	$	2,601	$	1,098	$	495	$	952


For the Year Ended December 31, 2008	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	898	$	274	$	424	$	158
Regulatory assets ^(a)		736		—		40		696
Nuclear fuel ^(b)		448		448		—		—
ARO accretion ^(c)		226		225		1		—

Total depreciation, amortization and accretion	$	2,308	$	947	$	465	$	854


For the Year Ended December 31, 2007	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	856	$	266	$	400	$	149
Regulatory assets ^(a)		664		—		40		624
Nuclear fuel ^(b)		431		431		—		—
ARO accretion ^(c)		232		231		1		—

Total depreciation, amortization and accretion	$	2,183	$	928	$	441	$	773

(a)	For PECO, reflects CTC amortization.

(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.


	Exelon and ComEd
	For the Year Ended December 31,
(In Millions)	2009		2008
Operating and maintenance for regulatory required programs ^(a)
Energy efficiency and demand response programs^(b)	$	59	$	25
Purchased power administrative costs		4		3

Total operating and maintenance for regulatory required programs	$	63	$	28

(a)	Costs for various legislative and/or regulatory programs are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause for Exelon and ComEd. An equal and offsetting amount has been reflected in operating revenues during the period.

(b)	As a result of the Illinois Settlement, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008. See Note 2 —Regulatory Issues for additional information.

317

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2009	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility ^(a)	$	481	$	—	$	232	$	249
Real estate		157		127		20		10
Payroll		114		65		23		12
Other		26		13		6		5

Total taxes other than income	$	778	$	205	$	281	$	276


For the Year Ended December 31, 2008	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility ^(a)	$	507	$	—	$	236	$	271
Real estate ^(b)		127		124		29		(26	)
Payroll		123		67		26		12
Other		21		6		7		8

Total taxes other than income	$	778	$	197	$	298	$	265


For the Year Ended December 31, 2007	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility ^(a)	$	527	$	—	$	258	$	269
Real estate ^(c)		139		117		26		(4	)
Payroll		108		57		23		11
Other		23		11		7		4

Total taxes other than income	$	797	$	185	$	314	$	280

(a)	Municipal and state utility taxes are also recorded in revenues on the Registrants’ Consolidated Statements of Operations.

(b)	PECO reflected amortization of the regulatory liability recorded in connection with the 2007 PURTA settlement, partially offset by current year property taxes.

(c)	PECO reflected a $17 million reduction of a reserve related to the PURTA tax settlement, partially offset by current year property taxes.


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Loss in equity method investments
Financing trusts	$	(24	)	$	—		$	—		$	(24	)
NuStart Energy Development, LLC		(3	)		(3	)		—			—

Total loss in equity method investments	$	(27	)	$	(3	)	$	—		$	(24	)


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Loss in equity method investments
Financing trusts	$	(25	)	$	—		$	(8	)	$	(16	)
NuStart Energy Development, LLC		(1	)		(1	)		—			—

Total loss in equity method investments	$	(26	)	$	(1	)	$	(8	)	$	(16	)

318

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2007	Exelon			Generation			ComEd			PECO
Income (loss) in equity method investments
Financing trusts	$	(14	)	$	—		$	(7	)	$	(7	)
TEG and TEP ^(a)		3			3			—			—
Synthetic fuel-producing facilities		(93	)		—			—			—
NuStart Energy Development, LLC		(2	)		(2	)		—			—

Total loss in equity method investments	$	(106	)	$	1		$	(7	)	$	(7	)

(a)	On February 9, 2007, Generation sold its ownership interests in TEG and TEP.


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	126		$	126		$	—		$	—
Net realized income on decommissioning trust funds—Non-Regulatory Agreement Units ^(a)		29			29			—			—
Net unrealized gains on decommissioning trust funds—Regulatory Agreement Units		801			801			—			—
Net unrealized gains on decommissioning trust funds—Non-Regulatory Agreement Units		227			227			—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)		(746	)		(746	)		—			—

Total decommissioning-related activities		437			437			—			—

Investment income		5			—			1			4
Net direct financing lease income		26			—			—			—
Interest income related to uncertain income tax positions^(c)		50			—			65			5
Realized gains on Rabbi trust investments		5			—			5			—
Other-than-temporary impairment to Rabbi trust investments ^(d)		(7	)		—			(7	)		—
Losses on early retirement of debt		(117	)		(71	)		—			—
Other		27			10			15			4

Other, net	$	426		$	376		$	79		$	13

319

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2008	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	43		$	43		$	—	$	—
Net realized income on decommissioning trust funds—Non-Regulatory Agreement Units ^(a)		16			16			—		—
Net unrealized losses on decommissioning trust funds—Regulatory Agreement Units		(1,022	)		(1,022	)		—		—
Net unrealized losses on decommissioning trust funds—Non-Regulatory Agreement Units		(324	)		(324	)		—		—
Regulatory offset to decommissioning trust fund-related activities ^(b)		777			777			—		—

Total decommissioning-related activities		(510	)		(510	)		—		—

Investment income		10			—			6		4
Net direct financing lease income		24			—			—		—
Interest income related to uncertain income tax positions		31			11			6		12
Income related to the termination of a gas supply guarantee		13			13			—		—
Other		25			17			6		2

Other, net	$	(407	)	$	(469	)	$	18	$	18


For the Year Ended December 31, 2007	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	387		$	387		$	—	$	—
Net realized income on decommissioning trust funds—Non-Regulatory Agreement Units ^(a)		120			120			—		—
Other-than-temporary impairment on decommissioning trust funds—Regulatory Agreement Units ^(e)		(83	)		(83	)		—		—
Other-than-temporary impairment on decommissioning trust funds—Non-Regulatory Agreement Units ^(e)		(9	)		(9	)		—		—
Regulatory offset to decommissioning trust fund-related activities ^(b)		(300	)		(300	)		—		—

Total decommissioning-related activities		115			115			—		—

Investment income		10			—			6		4
Gain on disposition of assets and investments, net		23			18			3		2
Net direct financing lease income		24			—			—		—
Recovery of tax credits related to Exelon’s investments in synthetic fuel-producing facilities		178			—			—		—
Interest income related to settlement of PJM billing dispute		5			4			—		1
Interest income related to uncertain income tax positions		61			—			41		20
Interest income related to PURTA tax appeal^(f)		17			—			—		17
Other		27			18			8		1

Other, net	$	460		$	155		$	58	$	45

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)	Includes the elimination of decommissioning trust fund-related activity for the Regulatory Agreement Units, which are subject to regulatory accounting, including the elimination of net realized income, other-than-temporary impairments and related

320

Combined Notes to Consolidated Financial Statements—(Continued)

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

income taxes. See Notes 7—Fair Value of Financial Assets and Liabilities and 11—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(c)	Primarily includes interest income at ComEd from the 2009 remeasurement of income tax uncertainties. See Note 10—Income Taxes for information regarding the Registrants’ tax positions.

(d)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009. See Note 7—Fair Value of Assets and Liabilities for additional information regarding the impairment.

(e)	Includes net unrealized losses of the trust funds.

(f)	On March 27, 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, during the third quarter of 2007, PECO recognized approximately $17 million of interest income associated with this matter.

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007.


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Cash paid (refunded) during the year
Interest (net of amount capitalized)	$	740		$	94		$	305		$	216
Income taxes (net of refunds)		982			668			63			368
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	536		$	240		$	192		$	47
Equity in losses of unconsolidated affiliates and investments		27			3			—			24
Provision for uncollectible accounts		149			2			85			63
Stock-based compensation costs		70			—			—			—
Other decommissioning-related activity ^(a)		(163	)		(163	)		—			—
Energy-related options ^(b)		46			46			—			—
ARO reduction ^(c)		(47	)		(47	)		—			—
Amortization of regulatory asset related to debt costs		25			—			21			4
Amortization of the regulatory liability related to the PURTA tax settlement ^(d)		(2	)		—			—			(2	)
Other-than-temporary impairment to Rabbi trust investments ^(e)		7			—			7			—
Inventory write-down related to plant retirements		17			17			—			—
Other		(13	)		6			4			5

Total other non-cash operating activities	$	652		$	104		$	309		$	141

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		23			—			13			10
Other current assets		(2	)		—			—			3	^(g)
Other noncurrent assets and liabilities		(134	)		(1	)		(75	)^(f)		(47	)

Total changes in other assets and liabilities	$	(113	)	$	(1	)	$	(62	)	$	(34	)

321

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Exelon		Generation		ComEd		PECO
Non-cash investing and financing activities
Change in ARC	$	67	$	67	$	—	$	—
Capital expenditures not paid		70		97		37		4
Purchase accounting adjustments		9		9		—		—

(a)

Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, which are subject to regulatory accounting, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all trust fund activity. See Note 11—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b)	Reclassification of energy-related option premiums to realized at settlement of contracts recorded in results of operations due to the settlement of the underlying transaction.

(c)	Represents the reduction in the ARO in excess of the existing ARC balances for Generation’s nuclear generating units that are not subject to regulatory agreement with respect to decommissioning trust funding (the former AmerGen units and the portions of the Peach Bottom units).

(d)

In March 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO received approximately $38 million of real estate taxes previously remitted. This refund was recorded as a regulatory liability. PECO began amortizing this regulatory liability and refunding the amount to customers in January 2008. The regulatory liability associated with the PURTA settlement was fully amortized in January 2009.

(e)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009. See Note 7—Fair Value of Assets and Liabilities for additional information regarding the impairment.

(f)	Relates primarily to a decrease in interest payable associated with the remeasurement of uncertain income tax positions. See Note 10—Income Taxes for additional information.

(g)	Relates primarily to prepaid utility taxes.


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Cash paid (refunded) during the year
Interest (net of amount capitalized)	$	716		$	107		$	300		$	216
Income taxes (net of refunds)		938			660			(41	)		379
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	314		$	139		$	101		$	32
Equity in losses of unconsolidated affiliates and investments		26			1			8			16
Provision for uncollectible accounts		247			17			71			160
Stock-based compensation costs		67			—			—			—
Other decommissioning-related activity ^(a)		219			219			—			—
Energy-related options		5			5			—			—
Amortization of regulatory asset related to debt costs		25			—			21			4
Amortization of the regulatory liability related to the PURTA tax settlement ^(b)		(36	)		—			—			(36	)
Net impact of the 2007 distribution rate case order ^(c)		22			—			22			—
Reduction of guarantees ^(d)		(55	)		(55	)		—			—
Other		36			6			41			18

Total other non-cash operating activities	$	870		$	332		$	264		$	194

Changes in other assets and liabilities:
Deferred/over-recovered energy costs	$	32		$	—		$	29		$	3
Other current assets		12			(11	)		14			(3	)^(e)
Other noncurrent assets and liabilities		(179	)		(70	)		(20	)		(14	)

Total changes in other assets and liabilities	$	(135	)	$	(81	)	$	23		$	(14	)

322

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Exelon		Generation		ComEd		PECO
Non-cash investing and financing activities
Change in ARC	$	128	$	128	$	—	$	—
Capital expenditures not paid		23		6		4		6
Capitalized employee incentives		4		—		3		1
Purchase accounting adjustments		10		10		—		—

(a)

Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, which are subject to regulatory accounting, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all trust fund activity. See Note 11-Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b)

In March 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO received approximately $38 million of real estate taxes previously remitted. This refund was recorded as a regulatory liability and PECO began amortizing this liability and refunding customers in January 2008.

(c)

In September 2008, as a result of the 2007 Rate Case order, ComEd recorded $37 million of fixed asset disallowances; $35 million was recorded as operating and maintenance expense and $2 million was recorded as depreciation expense. In addition, ComEd established regulatory assets totaling approximately $13 million associated with reversing previously incurred expenses deemed recoverable in future rates. See Note 2—Regulatory Issues for more information.

(d)	Includes reversal of Sithe guarantee of $38 million and Distrigas guarantee of $13 million.

(e)	Relates primarily to prepaid utility taxes.


For the Year Ended December 31, 2007	Exelon			Generation			ComEd			PECO
Cash paid during the year
Interest (net of amount capitalized)	$	879		$	96		$	267		$	243
Income taxes (net of refunds)		1,298			1,174			93			456
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	320		$	142		$	101		$	32
Provision for uncollectible accounts		132			4			58			71
Equity in losses (gains) of unconsolidated affiliates		106			(1	)		7			7
Other decommissioning-related activity ^(a)		(75	)		(75	)		—			—
Energy-related options^(b)		133			133			—			—
Gain on sale of investments, net		(18	)		(18	)		—			—
Loss on execution of sub-lease		72			72			—			—
Other		64			(1	)		40			(24	)

Total other non-cash operating activities	$	734		$	256		$	206		$	86

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(91	)		—		$	(97	)	$	6
Other current assets		(27	)		(7	)		(5	)		—
Other noncurrent assets and liabilities		(4	)		47			(17	)		(26	)

Total changes in other assets and liabilities	$	(122	)	$	40		$	(119	)	$	(20	)

323

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Exelon		Generation		ComEd		PECO
Non-cash investing and financing activities
Change in ARC	$	60	$	60	$	—	$	—
Declaration of dividend not paid as of December 31, 2007		331		—		—		—
Purchase accounting adjustments		11		11		—		—
Resolution of certain tax matters ^(c)		69		—		69		—
ComEd Transitional Funding Trust ^(d)(e)		25		—		25		—
Capital expenditures not paid		29		7		13		9

(a)

(b)	Reclassification of energy-related option premiums to realized at settlement of contracts recorded in results of operations due to the settlement of the underlying transaction.

(c)	Includes amounts recorded to goodwill resulting from the resolution of certain tax matters and the impact of adopting the current authoritative guidance for accounting for uncertain tax positions.

(d)	Amount includes $17 million previously reflected in prepaid interest. This amount did not impact ComEd’s Consolidated Statements of Operations or ComEd’s Consolidated Statements of Cash Flows.

(e)	ComEd applied $8 million of previously prepaid balances against the long-term debt to ComEd Transitional Funding Trust

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of December 31, 2009 and 2008.


December 31, 2009	Exelon		Generation		ComEd		PECO
Investments
Equity method investments:
Financing trusts ^(a)	$	20	$	—	$	6	$	13
Keystone Fuels, LLC		15		15		—		—
Conemaugh Fuels, LLC		19		19		—		—
NuStart Energy Development, LLC		1		1		—		—

Total equity method investments		55		35		6		13

Other investments:
Net investment in direct financing leases		602		—		—		—
Employee benefit trusts and investments ^(b)		67		11		28		18

Total investments	$	724	$	46	$	34	$	31

(a)	Includes investments in financing trusts which were not consolidated within the financial statements of Exelon. Investments in financing trusts were recorded in Other noncurrent assets on ComEd’s Consolidated Balance Sheets. See Note 1—Significant Accounting Policies for additional information.

(b)	The Registrants’ investments in these marketable securities are recorded at fair market value.

324

Combined Notes to Consolidated Financial Statements—(Continued)

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


December 31, 2008	Exelon		Generation		ComEd		PECO
Investments
Equity method investments:
Financing trusts ^(a)	$	45	$	—	$	6	$	39
Keystone Fuels, LLC		8		8		—		—
Conemaugh Fuels, LLC		14		14		—		—
NuStart Energy Development, LLC		2		2		—		—

Total equity method investments		69		24		6		39

Other investments:
Net investment in direct financing leases		577		—		—		—
Employee benefit trusts and investments ^(b)		69		9		34		15

Total investments	$	715	$	33	$	40	$	54

(a)

Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2008. Investments in financing trusts were recorded in Other noncurrent assets on ComEd’s Consolidated Balance Sheets. See Note 1—Significant Accounting Policies for additional information.

(b)	The Registrants’ investments in these marketable securities are recorded at fair market value.

Like-Kind Exchange Transaction (Exelon). Prior to the PECO/Unicom Merger in October 2000, 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. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to require the lessees to return the leasehold interests or to arrange a service contract with a third party for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. In the fourth quarter of 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases. As of December 31, 2009 and 2008, the components of the net investment in the direct financing leases were as follows:


	December 31,
	2009		2008
Estimated residual value of leased assets	$	1,492	$	1,492
Less: unearned income		890		915

Net investment in direct financing leases	$	602	$	577

325

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables provide additional information about liabilities of the Registrants at December 31, 2009 and 2008.


December 31, 2009	Exelon		Generation		ComEd		PECO
Accrued expenses
Compensation-related accruals ^(a)	$	401	$	202	$	107	$	35
Taxes accrued		264		385		62		3
Interest accrued		170		48		88		30
Severance accrued		36		14		10		1
Other accrued expenses		52		21		15		5

Total accrued expenses	$	923	$	670	$	282	$	74


December 31, 2008	Exelon		Generation		ComEd		PECO
Accrued expenses
Compensation-related accruals ^(a)	$	464	$	250	$	114	$	36
Taxes accrued		439		434		80		49
Interest accrued		155		27		89		29
Severance accrued		17		5		4		1
Other accrued expenses		76		45		19		5

Total accrued expenses	$	1,151	$	761	$	306	$	120

(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

The following tables provide information about accumulated OCI (loss) recorded (after tax) within Exelon’s Consolidated Balance Sheets as of December 31, 2009 and 2008:


December 31, 2009	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges		551			1,157			—			1
Pension and non-pension postretirement benefit plans		(2,640	)		—			—			—

Total accumulated other comprehensive income (loss)	$	(2,089	)	$	1,157		$	—		$	1


December 31, 2008	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges		564			855			—			2
Pension and non-pension postretirement benefit plans		(2,809	)		(20	)		—			—
Unrealized loss on marketable securities		(6	)		—			(5	)		—

Total accumulated other comprehensive income (loss)	$	(2,251	)	$	835		$	(5	)	$	2

326

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of December 31, 2009 and 2008.


December 31, 2009	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	883	$	—	$	883
Pension and other postretirement benefits		2,634		—		19
Deferred income taxes		842		20		822
Debt costs		144		125		19
Severance		95		95		—
Asset retirement obligations		65		49		16
MGP remediation costs		143		103		40
Rate case costs		8		7		1
RTO start-up costs		12		12		—
Financial swap with Generation—noncurrent		—		669		—
Under-recovered universal service fund costs ^(a)		2		—		2
DSP Program electric procurement contracts ^(b)		2		—		4
Other		42		16		28

Noncurrent regulatory assets		4,872		1,096		1,834
Financial swap with Generation—current		—		302		—
Under-recovered energy and transmission costs current asset ^(d)		56		56		—

Total regulatory assets	$	4,928	$	1,454	$	1,834

Regulatory liabilities
Nuclear decommissioning	$	2,229	$	1,918	$	311
Removal costs		1,212		1,212		—
Refund of PURTA taxes ^(c)		4		—		4
Deferred taxes		30		—		—
Over-recovered universal service fund costs ^(a)		2		—		2
Energy efficiency and demand response programs		15		15		—

Noncurrent regulatory liabilities		3,492		3,145		317
Over-recovered energy and transmission costs current liability ^(d)		33		11		22

Total regulatory liabilities	$	3,525	$	3,156	$	339

(a)	The universal services fund cost is a recovery mechanism that allows for PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of December 31, 2009, PECO was under-recovered for its electric program and over-recovered for its gas program.

(b)

PECO entered into block contracts to procure electric generation for its residential procurement class beginning January 1, 2011. As of December 31, 2009, PECO recorded a mark-to-market liability and this offsetting regulatory asset to account for changes in fair value. These block contracts were executed in accordance with the PAPUC-approved DSP Program and PECO will receive full cost recovery in rates.

(c)

In October 2009, PECO prevailed in a Pennsylvania Commonwealth Court case in which PECO had contested the assessment of a PURTA supplemental tax applicable to 1997. As a result, PECO will receive approximately $4 million of real estate taxes previously remitted in 2011. This refund is recorded as a regulatory liability. PECO will begin amortizing this regulatory liability and refunding the amount to customers in January 2011.

327

Combined Notes to Consolidated Financial Statements—(Continued)

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

(d)

The ComEd under-recovered or over-recovered energy and transmission costs represent purchased power related costs recoverable or refundable to customers under ComEd’s regulatory approved rates. In addition, PECO’s over-recovered energy costs represent gas supply related costs refundable to customers under PECO’s PAPUC PGC. Over-recovered costs are included in other current liabilities in Exelon’s, ComEd’s and PECO’s Consolidated Balance Sheets. ComEd and PECO pay a rate of return on over-recovered energy costs. See Note 2—Regulatory Issues for additional information.


December 31, 2008	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	1,666	$	—	$	1,666
Pension and other postretirement benefits		2,855		—		26
Deferred income taxes		826		16		810
Debt costs		169		146		23
Severance		116		116		—
Asset retirement obligations		128		112		16
MGP remediation costs		121		80		41
Rate case costs		15		14		1
RTO start-up costs		14		14		—
Financial swap with Generation—noncurrent		—		345		—
Other		30		15		14

Noncurrent regulatory assets		5,940		858		2,597
Financial swap with Generation—current		—		111		—
Under-recovered energy costs current asset^(a)		58		58		—

Total regulatory assets	$	5,998	$	1,027	$	2,597

Regulatory liabilities
Nuclear decommissioning	$	1,336	$	1,289	$	47
Removal costs		1,145		1,145		—
Refund of PURTA taxes^(b)		2		—		2
Deferred taxes		30		—		—
Energy efficiency and demand response programs		7		6		—

Noncurrent regulatory liabilities		2,520		2,440		49
Over-recovered energy costs current liability ^(a)		13		1		12

Total regulatory liabilities	$	2,533	$	2,441	$	61

(a)

(b)

Competitive Transition Charges. These charges represent PECO’s stranded costs that the PAPUC determined would be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The 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%.

328

Combined Notes to Consolidated Financial Statements—(Continued)

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

Pension and other postretirement benefits. As of December 31, 2009, $2,615 million represents regulatory assets related to the recognition of ComEd’s and PECO’s respective shares of the underfunded status of Exelon’s defined benefit postretirement plans as a liability on Exelon’s balance sheet. 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 the authoritative guidance for pensions and postretirement benefits. Exelon believes it is probable that these items will be recovered through rates by ComEd and PECO in future periods. See Note 13—Retirement Benefits for additional detail. In addition, $19 million is the result of PECO transitioning to the current authoritative guidance in 1993, which is recoverable in rates through 2012.

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 the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking 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 10—Income Taxes for additional information.

Debt costs. The reacquired debt costs represent premiums paid for the early extinguishment and refinancing of long-term debt, which are amortized over the life of the new debt issued to finance the debt redemption. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding.

Severance. 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.

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 11—Asset Retirement Obligations for additional information.

MGP remediation costs. Recovery of these items was granted to ComEd in the July 26, 2006 ICC rate order. For PECO, these costs represent estimated MGP-related environmental remediation costs which are recoverable through rates as prescribed in the 2008 joint settlement of the gas distribution rate case. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures.

Rate case costs. The ICC generally allows ComEd to receive recovery of rate case costs over three years. The ICC has issued orders allowing recovery of these costs on July 26, 2006 and September 10, 2008. Pursuant to the joint settlement of the 2008 gas distribution rate case, PECO is allowed recovery of rate case costs over two years.

DSP Program electric procurement contracts. These amounts represent an offset to the mark-to-market liability position of PECO’s procurement contracts for electric supply following the expiration of its generation rate caps on December 31, 2010. Recovery of electric procurement costs was granted to PECO in the PAPUC approval of their DSP Program and will occur in 2011 when the transactions under the contract are executed.

329

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 11—Asset Retirement Obligations for additional information.

Removal costs. These amounts represent funds received from customers to cover the future removal of property, plant and equipment which reduces rate base for ratemaking purposes.

Financial swap with Generation. To fulfill a requirement of the Illinois Settlement, ComEd entered into a five-year financial swap contract with Generation. Since the swap contract was deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period are recorded by ComEd as well as an offsetting regulatory asset or liability. ComEd recorded a regulatory asset related to its mark-to-market derivative liability position as of December 31, 2009 and 2008. The basis for the mark-to-market derivative position is based on the difference between the ComEd’s cost to purchase energy on the spot market and the contracted price. In Exelon’s consolidated financial statements, the fair value of the intercompany swap recorded by Generation and ComEd is eliminated. See Note 2—Regulatory Issues for additional information.

Deferred (over-recovered) energy costs current asset (liability). Starting in 2007, the ComEd costs are recoverable (refundable) under ComEd’s ICC and/or FERC-approved rates. ComEd’s deferred energy costs are earning (paying) a rate of return. The PECO costs represent gas supply related costs recoverable (refundable) under PECO’s PAPUC-approved rates. PECO’s deferred energy costs earn a rate of return. A return on over-recovered energy costs is paid to customers in addition to the over-recovered energy costs.

The regulatory assets related to pension and other postretirement benefits, deferred income taxes, MGP remediation costs, severance, financial swap with Generation, DSP Program and rate case costs are not earning a rate of return. Recovery of the regulatory assets for CTC, AROs, debt costs, RTO start-up costs, under-recovered universal service fund costs and deferred energy costs are earning a rate of return.

330

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. Generation, ComEd and PECO each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. PECO has two operating segments, electric and gas delivery, which are aggregated into one reportable segment primarily due to their similar economic characteristics and the regulatory environments in which they operate. 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			Intersegment Eliminations			Consolidated
Total revenues ^(a) :
2009	$	9,703	$	5,774	$	5,311	$	757		$	(4,227	)	$	17,318
2008		10,754		6,136		5,567		697			(4,295	)		18,859
2007		10,749		6,104		5,613		741			(4,291	)		18,916

Intersegment revenues ^(b):
2009	$	3,472	$	2	$	6	$	756		$	(4,227	)	$	9
2008		3,586		4		10		695			(4,295	)		—
2007		3,538		2		11		740			(4,291	)		—

Depreciation and amortization
2009	$	333	$	494	$	952	$	55		$	—		$	1,834
2008		274		464		854		42			—			1,634
2007		267		440		773		40			—			1,520

Operating expenses ^(a):
2009	$	6,408	$	4,931	$	4,614	$	840		$	(4,225	)	$	12,568
2008		6,760		5,469		4,868		758			(4,295	)		13,560
2007		7,357		5,592		4,666		924			(4,291	)		14,248

Interest expense, net:
2009	$	113	$	319	$	187	$	112		$	—		$	731
2008		136		348		226		132			(10	)		832
2007		161		318		248		124			(1	)		850

Income (loss) from continuing operations before income taxes:
2009	$	3,555	$	603	$	499	$	(236	)	$	(3	)	$	4,418
2008		3,388		329		475		(158	)		—			4,034
2007		3,387		245		737		(197	)		—			4,172

Income taxes:
2009	$	1,433	$	229	$	146	$	(102	)	$	6		$	1,712
2008		1,130		128		150		(91	)		—			1,317
2007		1,362		80		230		(226	)		—			1,446

331

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Generation		ComEd		PECO		Other			Intersegment Eliminations			Consolidated
Income (loss) from continuing operations:
2009	$	2,122	$	374	$	353	$	(134	)	$	(9	)	$	2,706
2008		2,258		201		325		(67	)		—			2,717
2007		2,025		165		507		29			—			2,726

Income (loss) from discontinued operations:
2009	$	—	$	—	$	—	$	1		$	—		$	1
2008		20		—		—		—			—			20
2007		4		—		—		6			—			10

Net income (loss):
2009	$	2,122	$	374	$	353	$	(133	)	$	(9	)	$	2,707
2008		2,278		201		325		(67	)		—			2,737
2007		2,029		165		507		35			—			2,736

Capital expenditures:
2009	$	1,977	$	854	$	388	$	54		$	—		$	3,273
2008		1,699		953		392		73			—			3,117
2007		1,269		1,040		339		26			—			2,674

Total assets:
2009	$	22,406	$	20,697	$	9,019	$	6,088		$	(9,030	)	$	49,180
2008		20,084		19,237		9,169		5,992			(6,936	)		47,546

(a)

For the years ended December 31, 2009, 2008 and 2007, utility taxes of $232 million, $236 million, and $258 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2009, 2008 and 2007, utility taxes of $249 million, $271 million and $269 million, respectively, are included in revenues and expenses for PECO.

(b)

The intersegment profit associated with Generation’s sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 2—Regulatory Issues for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.

332

Combined Notes to Consolidated Financial Statements—(Continued)

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

21. Related-Party Transactions (Exelon, Generation, ComEd and PECO)

Exelon

The financial statements of Exelon include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008			2007
Operating revenues from affiliates
CTFT ^(a)	$	—		$	3		$	3
PETT		3			5			6
PECO ^(b)		9			—			—
Other		—			—			1

Total operating revenues from affiliates	$	12		$	8		$	10

Fuel purchases from related parties
Keystone Fuels, LLC	$	56		$	73		$	46
Conemaugh Fuels, LLC		69			54			46

Total fuel purchases from related parties	$	125		$	127		$	92

Charitable contribution to Exelon Foundation ^(d)	$	10		$	—		$	50
Interest expense to affiliates, net
CTFT ^(a)	$	—		$	6		$	27
ComEd Financing II ^(c)		—			2			13
ComEd Financing III		13			13			13
PETT		51			101			139
PECO Trust III		6			6			6
PECO Trust IV		6			6			6
Other		1			(1	)		(1	)

Total interest expense to affiliates, net	$	77		$	133		$	203

Equity in earnings (losses) of unconsolidated affiliates and investments
ComEd Funding ^(a)	$	—		$	(8	)	$	(7	)
PETT		(24	)		(16	)		(7	)
NuStart Energy Development, LLC		(3	)		—			—
TEG and TEP ^(e)		—			—			3
Investment in synthetic fuel-producing facilities		—			—			(93	)
Other		—			(2	)		(2	)

Total equity in losses of unconsolidated affiliates and investments	$	(27	)	$	(26	)	$	(106	)

333

Combined Notes to Consolidated Financial Statements—(Continued)

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


	As of December 31, 2009		As of December 31, 2008
Investments in affiliates
ComEd Financing III	$	7	$	6
PETT		5		30
PECO Energy Capital Corporation		4		4
PECO Trust IV		4		5

Total investments in affiliates	$	20	$	45

Payables to affiliates (current)
ComEd Financing III	$	4	$	4
PECO Trust III		1		1

Total payables to affiliates (current)	$	5	$	5

Long-term debt to PETT and other financing trusts (including due within one year)
ComEd Financing III	$	206	$	206
PETT		415		1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt due to financing trusts	$	805	$	1,514

(a)

During 2008, ComEd fully paid its long-term debt obligations to CTFT and received its current receivable from CTFT. ComEd Funding liquidated its investment in CTFT and ComEd liquidated its investment in ComEd Funding. This resulted in the elimination of operating revenues and interest expense applicable to CTFT, and equity in losses of the unconsolidated affiliate, ComEd Funding.

(b)	The intersegment profit associated with Generation’s sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 2—Regulatory Issues for additional information.

(c)	ComEd Financing II was liquidated and dissolved upon repayment of the debt in 2008.

(d)	Exelon Foundation is a nonconsolidated not-for-profit Illinois corporation. The Exelon Foundation was established in 2007 to serve educational and environmental philanthropic purposes and does not serve a direct business or political purpose of Exelon.

(e)	Generation’s ownership interest in TEG and TEP was sold in 2007.

334

Combined Notes to Consolidated Financial Statements—(Continued)

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

Transactions involving Generation, ComEd, and PECO are further described in the tables below.

Generation

The financial statements of Generation include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008			2007
Operating revenues from affiliates
ComEd ^(a)	$	1,456		$	1,505		$	1,477
PECO ^(b)		2,016			2,081			2,061

Total operating revenues from affiliates	$	3,472		$	3,586		$	3,538

Fuel expense from related parties
PECO	$	1		$	1		$	3
ComEd		—			3			—
Keystone Fuels, LLC		56			73			46
Conemaugh Fuels, LLC		69			54			46

Total fuel purchases from related parties	$	126		$	131		$	95

Operating and maintenance from affiliates
ComEd ^(c)	$	2		$	1		$	2
PECO^(c)		6			9			8
BSC^(d)		298			275			254

Total operating and maintenance from affiliates	$	306		$	285		$	264

Equity in earnings (losses) of investments
TEG and TEP ^(e)	$	—		$	—		$	3
NuStart Energy Development, LLC		(3	)		(1	)		(2	)

Total equity in earnings (losses) of investments	$	(3	)	$	(1	)	$	1

Cash distribution paid to member	$	2,276		$	1,545		$	2,357
Contribution from member	$	57		$	86		$	54

335

Combined Notes to Consolidated Financial Statements—(Continued)

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


	As of December 31, 2009		As of December 31, 2008
Market-to-market derivative assets with affiliate (current)
ComEd^(f)	$	302	$	111
Receivables from affiliates (current)
ComEd^(a)(g)(h)		123		151
PECO ^(b)		174		126

Total receivables from affiliates (current)	$	297	$	277

Receivable from affiliate (noncurrent)
Exelon ⁽ⁱ⁾	$	1	$	1
Market-to-market derivative assets with affiliate (noncurrent)
ComEd ^(f)	$	669	$	345
PECO ^(l)		2		—
Prepaid voluntary employee beneficiary association trust
Generation ^(j)	$	—	$	2
Payables to affiliates (current)
Exelon ⁽ⁱ⁾	$	7	$	44
BSC ^(d)		73		34

Total payables to affiliates (current)	$	80	$	78

Payables to affiliates (noncurrent)
ComEd decommissioning ^(k)	$	1,917	$	1,289
PECO decommissioning ^(k)		311		47

Total payables to affiliates (noncurrent)	$	2,228	$	1,336

(a)

Generation has a SFC and an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 2—Regulatory Issues for additional information.

(b)

Generation has a PPA with PECO, as amended, to provide the full energy requirements to PECO through 2010. See Note 18—Commitments and Contingencies for more information regarding the PPA. Generation has a five-year agreement with PECO to sell AECs. See Note 2—Regulatory Issues for additional information.

(c)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.

(d)	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.

(e)	Generation’s ownership interest in TEG and TEP was sold in 2007.

(f)	Represents the fair value of Generation’s five-year financial swap contract with ComEd.

(g)

Under the Illinois Settlement Legislation, Generation is responsible to contribute to rate relief programs for ComEd customers, which are issued through ComEd. As of December 31, 2009 and 2008, Generation had a $0 million and $10 million payable, respectively, which is netted against the receivable from ComEd. See Note 2—Regulatory Issues for additional information.

(h)	As of December 31, 2009, Generation had a $24 million receivable from ComEd associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 2—Regulatory Issues and Note 8—Derivative Financial Instruments for additional information.

(i)	In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

(j)

The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans accumulated at December 31, 2008 due to actuarially determined contribution rates, which are the basis for Generation’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.

336

Combined Notes to Consolidated Financial Statements—(Continued)

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

(k)

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 11—Asset Retirement Obligations.

(l)	Represents the fair value of Generation’s block contracts with PECO.

ComEd

The financial statements of ComEd include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009		2008			2007
Operating revenues from affiliates
Generation	$	2	$	4		$	2
CTFT ^(a)		—		3			3

Total operating revenues from affiliates	$	2	$	7		$	5

Purchased power from affiliate
Generation ^(b)	$	1,456	$	1,505		$	1,477
Operating and maintenance from affiliate
BSC ^(c)	$	165	$	168		$	196
Interest expense to affiliates, net
CTFT ^(a)	$	—	$	6		$	27
ComEd Financing II^(a)		—		2			13
ComEd Financing III		13		13			13

Total interest expense to affiliates, net	$	13	$	21		$	53

Equity in losses of unconsolidated affiliate
ComEd Funding ^(a)	$	—	$	(8	)	$	(7	)
Capitalized costs
BSC ^(c)	$	72	$	55		$	72
Cash dividends paid to parent	$	240	$	—		$	—
Contribution from parent	$	8	$	14		$	28

337

Combined Notes to Consolidated Financial Statements—(Continued)

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


	As of December 31, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust ^(d)	$	7	$	9
Investment in affiliate ^(e)
ComEd Financing III		6		6
Receivable from affiliates (noncurrent)
Generation ^(g)	$	1,917	$	1,289
Other		3		2

Total receivable from affiliates (noncurrent)	$	1,920	$	1,291

Payables to affiliates (current)
Generation ^(b)(h)(i)	$	123	$	151
BSC ^(c)		48		22
ComEd Financing III		4		4
Other		2		2

Total payables to affiliates (current)	$	177	$	179

Mark-to-market derivative liability with affiliate (current)
Generation ^(f)	$	302	$	111
Mark-to-market derivative liability with affiliate (noncurrent)
Generation ^(f)	$	669	$	345
Long-term debt to ComEd financing trust
ComEd Financing III	$	206	$	206

(a)

During 2008, ComEd fully paid its long-term debt obligations to CTFT and received its current receivable from the CTFT. ComEd Funding liquidated its investment in CTFT and ComEd liquidated its investment in ComEd Funding. This resulted in the elimination of operating revenues and interest expense applicable to CTFT, and equity in losses of the unconsolidated affiliate, ComEd Funding. In addition, ComEd Financing II was liquidated and dissolved upon repayment of the debt during 2008.

(b)

ComEd procures a portion of its electricity supply requirements from Generation under a SFC and an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement. See Note 2—Regulatory Issues and Note 8—Derivative Financial Instruments for additional information.

(c)	ComEd 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.

(d)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.

(e)	Investments in affiliates are included in other noncurrent assets.

(f)	To fulfill a requirement of the Illinois Settlement, ComEd entered into a five-year financial swap with Generation.

(g)

ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. 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.

(h)	As of December 31, 2009, ComEd had a $24 million payable to Generation associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 2—Regulatory Issues and Note8— Derivative Financial Information for additional information.

(i)

Under the Illinois Settlement Legislation, Generation is responsible to contribute to rate relief programs for ComEd customers, which are issued through ComEd. As of December 31, 2009 and 2008, ComEd had a $0 million and $10 million receivable, respectively, which is netted against the payable to Generation. See Note 2—Regulatory Issues for additional information.

338

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO

The financial statements of PECO include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008			2007
Operating revenues from affiliates
Generation ^(a)	$	6		$	10		$	11
PETT ^(b)		3			4			6

Total operating revenues from affiliates	$	9		$	14		$	17

Purchased power from affiliate
Generation ^(c)	$	2,005		$	2,083		$	2,059
Operating and maintenance from affiliates
BSC ^(d)	$	94		$	92		$	115
Generation		1			(2	)		2

Total operating and maintenance from affiliates	$	95		$	90		$	117

Interest expense to affiliates, net
PETT	$	51		$	101		$	139
PECO Trust III		6			6			6
PECO Trust IV		6			6			6
Other		—			1			3

Total interest expense to affiliates, net	$	63		$	114		$	154

Equity in losses of unconsolidated affiliates
PETT	$	(24	)	$	(16	)	$	(7	)
Capitalized costs
BSC ^(d)	$	24		$	21		$	30
Cash dividends paid to parent	$	312		$	480		$	562
Repayment of receivable from parent	$	320		$	284		$	306
Contribution from parent	$	27		$	36		$	32

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Combined Notes to Consolidated Financial Statements—(Continued)

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


	As of December 31, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust ^(e)	$	1	$	2
Investments in affiliates
PETT	$	5	$	30
PECO Energy Capital Corporation		4		4
PECO Trust IV		4		5

Total investments in affiliates	$	13	$	39

Receivable from affiliate (noncurrent)
Generation decommissioning ^(f)	$	311	$	47
Mark-to-market derivative liability with affiliate (noncurrent)
Generation ^(h)	$	2	$	—
Payables to affiliates (current)
Generation ⁽ⁱ⁾	$	174	$	126
BSC^(d)		13		16
Exelon		1		1
PECO Trust III		1		1

Total payables to affiliates (current)	$	189	$	144

Long-term debt to PETT and other financing trusts (including due within one year)
PETT	$	415	$	1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt to financing trusts	$	599	$	1,308

Shareholders’ equity—receivable from parent ^(g)	$	180	$	500

(a)	PECO provides energy to Generation for Generation’s own use.

(b)	PECO receives a monthly administrative servicing fee from PETT based on a percentage of the outstanding balance of all series of transition bonds.

(c)	PECO obtains all of its electric supply from Generation through 2010 under a PPA.

(d)	PECO 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.

(e)

The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.

(f)

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.

(g)	PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled by December 31, 2010.

(h)	PECO entered into block contracts with Generation to procure electric generation for its residential procurement class beginning January 1, 2011 in accordance with its PAPUC-approved DSP Program.

(i)	PECO obtains all of its electric supply from Generation through 2010 under a PPA. In addition, PECO has a five-year agreement with Generation to purchase AECs. See Note 2—Regulatory Issues for additional information on AECs.

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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				Net Income
	2009		2008		2009		2008		2009		2008
Quarter ended:
March 31	$	4,722	$	4,517	$	1,254	$	1,123	$	712	$	581
June 30		4,141		4,622		1,017		1,430		657		748
September 30		4,339		5,228		1,403		1,413		757		700
December 31		4,116		4,493		1,076		1,333		581		707


	Average Basic Shares Outstanding (in millions)		Net Income per Basic Share
	2009	2008	2009		2008
Quarter ended:
March 31	659	659	$	1.08	$	0.88
June 30	659	657		1.00		1.14
September 30	660	658		1.15		1.06
December 31	660	658		0.88		1.07


	Average Diluted Shares Outstanding (in millions)		Net Income per Diluted Share
	2009	2008	2009		2008
Quarter ended:
March 31	661	664	$	1.08	$	0.88
June 30	661	662		0.99		1.13
September 30	662	662		1.14		1.06
December 31	662	661		0.88		1.07

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


	2009								2008
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	51.98	$	54.47	$	51.46	$	58.98	$	63.84	$	92.13	$	91.84	$	87.25
Low price		45.90		47.30		44.24		38.41		41.23		60.00		81.00		70.00
Close		48.87		49.62		50.12		45.39		55.61		62.62		89.96		81.27
Dividends		0.525		0.525		0.525		0.525		0.525		0.500		0.500		0.500

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:


	Operating Revenues				Operating Income				Net Income
	2009		2008		2009		2008		2009		2008
Quarter ended:
March 31	$	2,601	$	2,482	$	862	$	739	$	528	$	438
June 30		2,378		2,756		676		1,138		512		653
September 30		2,445		3,073		1,046		1,140		657		635
December 31		2,278		2,443		711		976		425		553

ComEd

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


	Operating Revenues				Operating Income				Net Income
	2009		2008		2009		2008		2009		2008
Quarter ended:
March 31	$	1,553	$	1,440	$	206	$	170	$	114	$	41
June 30		1,389		1,425		209		141		116		35
September 30		1,475		1,729		203		138		46		33
December 31		1,357		1,542		224		217		98		91

PECO

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


	Operating Revenues				Operating Income				Net Income on Common Stock
	2009		2008		2009		2008		2009		2008
Quarter ended:
March 31	$	1,514	$	1,476	$	210	$	198	$	112	$	96
June 30		1,204		1,277		154		138		70		57
September 30		1,327		1,441		172		190		91		89
December 31		1,266		1,372		160		174		77		79

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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 2009, 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) information relating to that registrant, including its consolidated subsidiaries, that is required to be included in filings under the Securities Exchange Act of 1934, 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, 2009, 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. However, there have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, Exelon’s internal control over financial reporting.

Exelon, Generation, ComEd and PECO

Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2009. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2009 and, therefore, concluded that each registrant’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. Financial Statements and Supplementary Data.

ITEM 9B.

OTHER INFORMATION

Exelon, Generation, ComEd and PECO

None.

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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 February 5, 2010.

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 2010 proxy statement (2010 Exelon Proxy Statement) to be filed with the SEC before April 30, 2010 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 Bruce G. Wilson, Senior Vice President, Deputy General Counsel, 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 2009.

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 February 5, 2010.

Directors

Generation operates as a limited liability company and has no board of directors.

344

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 2010 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 February 5, 2010.

Directors

Frank M. Clark. Age 64. Chairman and Chief Executive Officer since November 28, 2005. Previously Executive Vice President and Chief of Staff of Exelon and President of ComEd from 2004 to 2005; Senior Vice President, Exelon, and Executive Vice President of Exelon Energy Delivery and President of ComEd from 2003 to 2004. He is a director of Aetna, Inc. (insurance) and Waste Management, Inc. (environmental services). Mr. Clark has worked for ComEd for over forty years and has extensive knowledge of ComEd’s business and regulatory matters.

James W. Compton. Age 71. Director of ComEd since September 18, 2006. President and Chief Executive Officer of Chicago Urban League from 1978 through 2006; President and Chief Executive Officer of the Chicago Urban League Development Corporation from 1980 through 2006. Mr. Compton has extensive knowledge of ComEd and its business, having previously served as a director of ComEd from 1989-2000 and having served as a director of a community-based bank. In addition, he is very familiar with ComEd’s customers and contributes to ComEd’s outreach to diverse groups in Chicago.

Peter V. Fazio, Jr. Age 70. Director of ComEd since October 29, 2007. A partner of the law firm of Schiff Hardin, LLP. A past Chairman, Executive Committee Member and Managing Partner of Schiff Hardin. In addition to his general legal expertise, Mr. Fazio previously served as general counsel of another electric and gas utility and brings the ComEd board knowledge of utility regulatory and legal issues.

Sue L. Gin. Age 67. Director of ComEd 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). She is also a director of Exelon and of Centerplate, Inc. and was a director of Briazz, Inc. (restaurants and catering) from 2003-2004. As a leader in the Chicago business community and as the chief executive of a privately–held Chicago-based business, Ms. Gin is familiar with the Chicago economy and the needs of Chicago businesses served by ComEd. As a female member of the Asian-American community, Ms. Gin also brings diversity to the board and contributes to ComEd’s diversity initiatives and community outreach.

Edgar D. Jannotta. Age 78. Director of ComEd 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. He is also a director of Aon Corporation (insurance) and Molex, Inc. (automobile parts) and formerly served as a director of AAR Corporation and Bandag, Incorporated.

345

Mr. Jannotta was a director of ComEd from 1994 to 2000 and a director of Exelon from 2000 through 2007. He is a leader in the Chicago business community and has extensive financial and investment banking experience that gives him knowledge of credit and capital markets and the needs of Chicago businesses served by ComEd.

Edward J. Mooney. Age 68. Director of ComEd since October 16, 2006. From March 2000 to March 2001, was Delegue General-North America of Suez Lyonnaise. Since March 2000 Mr. Mooney was chairman and chief executive officer of Nalco Chemical Company from 1994 until March 2000. He is also a director of Northern Trust Corporation, FMC Corporation, FMC Technologies, Inc., Cabot Microelectronics Corporation and Polyone Corporation. Mr. Mooney’s experience as a CEO and as a director of other corporations, as well as his involvement in the Chicago business community, make him a valuable member of the ComEd board.

Michael H. Moskow. Age 72. Director of ComEd since January 28, 2008. Vice Chairman and a Senior Fellow at the Chicago Council on Global Affairs. President and Chief Executive Officer (CEO) of the Federal Reserve Bank of Chicago from 1994 to 2007. He is also director of Discover Financial Services, Diamond Management and Technology Consultants, Inc., Northern Trust Mutual Funds and Taylor Capital Group. Mr. Moskow is a recognized leader in the Chicago business community with knowledge of the economy of the Midwestern United States and the northern Illinois communities ComEd serves. His business experience and service on the boards of other companies and organizations enable him to contribute to the work of the ComEd board.

John W. Rogers, Jr. Age 51. Director of ComEd since November 28, 2005. Founder, Chairman and CEO of Ariel Investments (an institutional money management firm). He is also a director of Exelon, Aon Corporation and McDonald’s Corporation. He previously served as a director of GATX Corporation (rail, marine and industrial equipment leasing) from 1998-2004, Bank One Corporation from 1998-2004, and Bally Total Fitness (fitness and health clubs) from 2003-2006. Mr. Rogers’ experience on the boards of a number of major corporations based in Chicago in a variety of industries has made him a leader in the Chicago business community with perspective into Chicago business developments. His role in Chicago’s and the nation’s African-American community brings diversity to the board and emphasis to ComEd’s diversity initiatives and community outreach. His experience in investment management and financial markets and as a director of an insurance brokerage and services company are useful to ComEd.

John W. Rowe. Age 64. Director of ComEd since April 27, 2009. Mr. Rowe has served as Chairman and Chief Executive Officer of Exelon since April of 2002 and he has been a Director of Exelon since its formation in 2000. At various times since 2000 he has also held the title of President of Exelon and from 2000 through April 2002 he was also Co-Chief Executive Officer of Exelon. Mr. Rowe is also a director of PECO, The Northern Trust Company and Sunoco, Inc. and formerly served as a director of UnumProvident Corporation from 1999 (upon the merger of Unum Corporation into Provident Companies, Inc.) to 2005; he had previously served on Unum Corporation Board from 1988, Fleet Boston Financial Corporation (bank) from 1999 (when BankBoston was acquired by Fleet Boston) to 2002 and Wisconsin Central Transportation Corporation from 1998 to 2001 (when it was acquired by Canadian National Railway). Mr. Rowe has an aggregate of over 25 years experience as the CEO of Exelon and other utilities.

Jesse H. Ruiz. Age 44. Director of ComEd since October 16, 2006. Partner at the law firm Drinker, Biddle & Reath LLP; Chairman of the Illinois State Board of Education. Mr. Ruiz’s legal and governmental experience in the city and state where ComEd’s business is conducted has enabled him to contribute to the ComEd board. Mr. Ruiz contributes to ComEd’s outreach to diverse groups.

Richard L. Thomas. Age 79. Director of ComEd since November 28, 2005. Member of the audit committee. Chairman of First Chicago NBD Corporation (banking and financial services) from December

346

1995 through May 1996 and the First Chicago Corporation from January 1992 through December 1996. Served as a director of Exelon from 2000 through 2007, and also previously as a director of Sara Lee Corporation (consumer goods), PMI Group, Inc., IMC Global Inc, and The SABRE Group Holdings, Inc. Mr. Thomas was a director of ComEd from 1998 through 2000 and a director of Exelon from 2000 through 2007. Mr. Thomas is a recognized leader in the Chicago business community with knowledge of the markets that ComEd serves. His experience as a CEO and his experience as a director of other companies enable him to contribute to the ComEd board. His experience as a banker and knowledge of the credit and capital markets are valuable to the ComEd board.

Audit Committee

The ComEd audit committee consists of 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 Exelon’s Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of Exelon’s 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 February 5, 2010.

Directors

The board is classified into three classes, with two directors in Class I, three directors in Class II and three directors in Class III.

John W. Rowe. Age 64. Class I director. Mr. Rowe has served as Chairman and Chief Executive Officer of Exelon since April of 2002 and he has been a Director of Exelon since its formation in 2000. At various times since 2000 he has also held the title of President of Exelon and from 2000 through April 2002 he was also Co-Chief Executive Officer of Exelon. Mr. Rowe is also a director of ComEd, The Northern Trust Company and Sunoco, Inc. and formerly served as a director of UnumProvident Corporation, from 1999 (upon the merger of Unum Corporation into Provident Companies, Inc.) to 2005; he had previously served on Unum Corporation Board from 1988, Fleet Boston Financial Corporation (bank) from 1999 (when BankBoston was acquired by Fleet Boston) to 2002 and Wisconsin Central Transportation Corporation from 1998 to 2001 (when it was acquired by Canadian National Railway). Mr. Rowe has an aggregate of over 25 years’ experience as the CEO of Exelon and other utilities.

347

M. Walter D’Alessio. Age 76. Class II director. Director since July 23, 2007. Vice Chairman of NorthMarq Capital (a real estate investment banking firm) and Senior Managing Director of NorthMarq Advisors, LLC (a real estate consulting group), positions that he has held since July 2003. Chairman and CEO of Legg Mason Real Estate Services, Inc. from 1982 through July 2003. Also Chairman of the Board of Directors of Brandywine Real Estate Investment Trust, where he has been a trustee since 1996, and chair of Independence Blue Cross, where he has been a director since 1991, a director of the Federal Home Loan Bank Board of Pittsburgh since 2008, and a director of the Pennsylvania Real Estate Investment Trust since 2005. He is also a director of Exelon. Mr. D’Alessio is a leader in the Philadelphia business community and has knowledge of the greater Philadelphia metropolitan area and economic trends in the region, particularly with respect to real estate development. Mr. D’Alessio contributes to the PECO board through his long history as a business leader and as a director of other business organizations.

Nelson A Diaz. Age 62. Class II director. Director since July 23, 2007. Of Counsel to Cozen O’Connor, a Philadelphia-based law firm since May 2007. Previously he was a partner of the law firm Blank Rome LLP from March 2004 through May 2007 and from February 1997 through December 2001. He also served as City Solicitor of the City of Philadelphia from December 2001 through January 2004 and as General Counsel, United States Department of Housing and Urban Affairs, from 1993 to 1997. He is also a director of Exelon. Judge Diaz’s legal and governmental experience at the Federal level and in a city and state where PECO’s business is conducted has enabled him to contribute to the board on matters related to Federal, state and local regulation and public policy. In addition, Judge Diaz’s Puerto Rican heritage adds diversity to the PECO board. He serves on the boards of the National Association for Hispanic Elderly, the U.S. Hispanic Leadership Institute and the United States Hispanic Advocacy Association. He is active in Philadelphia government and community affairs and neighborhood development and has made contributions to PECO’s outreach to diverse groups within Philadelphia and neighboring communities.

Rosemarie B. Greco. Age 63. Class I director. Director since July 23, 2007. Senior Adviser to the Governor of Pennsylvania-Health Care Reform. She served as the director of the Governor’s Office of Health Care Reform for the Commonwealth of Pennsylvania from January 2003 through December 2008. Founding principal of GRECOVentures Ltd. (a private management consulting firm). Formerly President of CoreStates Financial Corporation and Former Director, President and CEO of CoreStates Bank, N.A. She is also a director of Sunoco, Inc. since 1998, a trustee of Pennsylvania Real Estate Investment Trust since 1997 and a trustee of SEI I Mutual Funds, a subsidiary of SEI Investments, Co. since 1999. She is also a director of Exelon. Her experience in the banking industry in Philadelphia has given her insight into the needs of the bank’s clients, who are also customers of PECO. Ms. Greco’s role as a female executive has brought diversity to PECO’s board, and she has contributed to PECO’s diversity initiatives. Her experience as a CEO with responsibility for overseeing the quality of operations is a useful background for her work on operational issues at PECO. Ms. Greco’s experience as a CEO, a management consultant, and a member of a number of corporate boards contribute to her effectiveness as a member of the PECO board.

Charisse R. Lillie. Age 57. Class II director. Director since January 1, 2010. Vice President of Community Investment for Comcast Corporation and Executive Vice President of the Comcast Foundation since 2008. She served as Vice President of Human Resources for Comcast Corporation and Senior Vice President of Human Resources for Comcast Cable from 2005 to 2008. She was a partner in the law firm of Ballard, Spahr, Andrews & Ingersoll, LLP from January 1992 to February 2005. She also serves on the boards of Howard University, The Franklin Institute Science Museum, the American Arbitration Association, the Penn Mutual Life Insurance Company, the United Way of Southeastern Pennsylvania, and the Pyramid Club. Ms. Lillie’s legal and regulatory experience and experience on the boards of other businesses and organizations enable her to contribute to the PECO board. She brings diversity to the PECO board and will contribute to PECO’s diversity initiatives.

348

Denis P. O’Brien. Age 49. Class III director. Director since June 30, 2003. Executive Vice President of Exelon; President and Chief Executive Officer of PECO since August 2007. President of PECO from 2003 to 2007. Mr. O’Brien has spent his entire career in PECO’s operations and has extensive knowledge of PECO’s business and regulatory matters.

Thomas J. Ridge. Age 64. Class III director. Director since July 23, 2007. President, Ridge Global LLC and strategic limited partner in Doheny Global Group, a U.S.-based international developer of energy facilities. Secretary of the United States Department of Homeland Security from January 2003 through January 2005, and the Assistant to the President for Homeland Security (an Executive Office created by President Bush) from October 2001 through December 2002. He served as Governor of the Commonwealth of Pennsylvania from 1994 through October 2001. He is also a director of Exelon, The Hershey Company (chocolate and sugar confectionary) since 2007 and Vonage Holdings Corp. (software technology for voice and messaging services) since 2005, and Brightpoint, Inc. since 2009. He previously served as a director of Home Depot Corporation (home improvement specialty retailer) from 2005-2007. Governor Ridge’s governmental service at the Federal level and in Pennsylvania is valued by the board. His Department of Homeland Security experience provides valuable insight into issues relating to the security of PECO’s transmission and distribution facilities. His service as a director of other companies brings additional perspective to the PECO board, which benefits greatly from Governor Ridge’s insights from his experience in state government and his expertise on matters relating to the security of critical infrastructure.

Ronald Rubin. Age 79. Class III director. Director since July 23, 2007. Chairman and Chief Executive Officer of the Pennsylvania Real Estate Investment Trust (a real estate management and development company). Mr. Rubin was a director of PECO from 1988 through 2000 and a director of Exelon from 2000 through 2007. He previously served as a director of Continental Bank and Midlantic Bank. Mr. Rubin is active in the Philadelphia business community and has knowledge of the greater Philadelphia metropolitan area and economic trends in the region, particularly with respect to real estate development. Mr. Rubin contributes to the PECO board through his long history as a business leader and as a director of other business organizations.

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 2010 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 Exelon’s Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of Exelon’s 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.

349

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Executive Summary

Effect of Financial Performance on Incentive Compensation

Exelon’s executive compensation programs are designed to motivate and reward senior management to achieve Exelon’s vision of being the best group of electric generation and electric and gas delivery companies in the United States, providing superior value for Exelon’s customers, employees, investors and the communities Exelon serves. Exelon’s results for 2009 as compared to 2007 and 2008 demonstrate that Exelon’s incentive compensation is consistent with Exelon’s performance. Exelon’s annual incentive program (“AIP”) is based to a significant extent on adjusted (non-GAAP) operating earnings per share, and its performance share award program is based on the relative total shareholder return for Exelon as compared to the Dow Jones Utility Index (60%) and the Standard & Poor’s 500 Index (40%). Exelon had strong results in 2007 and 2008, when Exelon’s adjusted (non-GAAP) operating earnings per share were $4.32 and $4.20, respectively. Total shareholder return for the 2005-2007 performance period was at the 68.7^th percentile of the Dow Jones Utility Index and the 89^th percentile of the Standard & Poor’s 500 Index, while for the 2006-2008 performance period it was at the 75^th percentile of the Dow Jones Utility Index and the 85.6^th percentile of the Standard & Poor’s 500 Index. This performance resulted in high incentive compensation payouts for 2007 and 2008. However, as a result of decreasing electricity sales, lower power prices, unfavorable weather, and increased pension and post-retirement benefits costs, partially offset by cost savings initiatives, Exelon’s results in 2009 declined. Exelon’s 2009 adjusted (non-GAAP) operating earnings per share were $4.12 and its total shareholder return for the 2007-2009 performance period was at the 37.5 percentile of the Dow Jones Utility Index and the 49.5 percentile of the Standard & Poor’s 500 Index. Exelon’s incentive compensation programs worked as designed to pay for performance, resulting in significantly lower incentive compensation payouts for 2009 as compared to the two prior years. Because earnings were below 150% of target in 2008 and below target in 2009, the shareholder protection features in the annual incentive plan took effect and limited the annual incentive payouts on operating company/business unit key performance indicator goals. The following table shows the correlation between levels of financial performance and incentive compensation in 2007, 2008 and 2009:


Year	Adjusted (non- GAAP) Earnings Per Share		% of Target For Earnings Goals in Annual Incentive Plan (AIP) (a)		Limit on % of Payout for Other Goals in AIP based on Earnings		Total Shareholder Return %ile as compared to Dow Jones Utility Index		% of Target		Total Shareholder Return %ile as compared to S&P 500 Index		% of Target		Performance Share Unit Payout as % of Target (60% DJUI performance 40% S&P 500 performance)
2007	$	4.32	156.67	%*	200	%	68.7	%	174.85	%	89.0	%	200.0	%	184.9	%
2008		4.20	116.67		150		75.0		200.00		85.6		200.0		200.0
2009		4.12	97.00		100		37.5		75.00		49.5		99.1		84.6

*	Percentage for payout of AIP was reduced by 2.5% to 152.7% because of performance on a customer satisfaction measure.

For additional information about Exelon’s financial results for 2008 and 2009, see Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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Value of Compensation Actually Paid to Named Executive Officers

The valuation methods specified by the SEC rules for equity compensation reported in the Summary Compensation Table overstate the value of equity compensation in Exelon’s situation, where 2009 grant date fair value for performance share units for the 2007-2009 performance period is based in part on historical data for the previous two plan years, which resulted in a high valuation due to strong performance in the 2005-2007 and 2006-2008 performance periods (when Exelon’s performance share program paid out at 184.9% of target and 200% of target, respectively, resulting in a valuation at 161% of target for the 2007-2009 performance period). The actual value of the 2007-2009 performance shares granted in January 2009 and awarded in January 2010 is significantly lower, reflecting both the actual performance at the award date and the decline in the stock price between the grant date and the award date. Similarly, the target number of performance shares for the 2006-2008 performance period was based on the January 2008 stock price of approximately $73, while the shares awarded in January 2009 were worth approximately $57. As a result, while Exelon’s total shareholder return performance was at 200% of target, as described below, the value of the shares paid out was only about 153% of the target value. In addition, valuation of stock options in the Summary Compensation Table is overstated to the extent that the strike price of stock options is higher than the current price of Exelon’s stock. None of the stock options granted since January 2006 is in the money; the 2006 strike price was $58.55; 2007, $59.96; 2008, $73.29; and 2009, $56.51, while the price of Exelon’s common stock on January 25, 2010 was $46.09. The following table presents the compensation actually paid to Exelon’s named executive officers (NEOs). Values for non-equity compensation are the same as in the Summary Compensation Table. Equity compensation is valued using the actual number of performance shares awarded at the end of the performance period multiplied by the stock price on the award date and no value for stock options that are not in the money, instead of grant date fair values.

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Exelon, Generation and PECO

Compensation Actually Paid to NEOs

(Equity Valued at Actual Value on Award Date Instead of Grant Date Fair Value)


Name and Principal Position (A)	Year (B)	Salary ($) (C)		Bonus ($) (D)		Stock Awards Valued at Award Date ($) (E)		Value of In the Money Stock Options at 1/25/2010 ($) (F)		Non-Equity Incentive Plan Compensation ($) (G)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($) (H)		All Other Compen- sation ($) (I)		Total ($) (J)
Rowe	2009	$	1,468,077	—		$	2,717,743	$	—	$	1,573,825	$	173,566	$	416,947	$	6,350,158
	2008		1,474,423	—			5,877,040		—		1,835,166		830,272		400,192		10,417,093
	2007		1,361,154	—			8,808,359		—		1,680,249		504,385		418,026		12,772,173

O’Brien	2009		532,923	—			538,101		—		395,970		233,772		55,464		1,756,230
	2008		495,538	—			1,175,408		—		428,934		105,978		175,687		2,381,545
	2007		450,154	—			1,219,619		—		468,642		99,320		96,339		2,334,074

Hilzinger	2009		442,769	13,079			261,238		—		261,579		85,891		31,725		1,096,281
	2008		408,627	—			942,300		—		318,750		57,492		143,916		1,871,085

Barnett	2009		307,996	—			163,758		—		153,788		55,038		23,407		703,987
	2008		297,308	(16,498	)		361,664		—		148,477		35,808		561,590		1,388,349
	2007		283,969	50,000			542,053		—		221,075		33,065		80,037		1,210,199

Crane	2009		821,154	—			882,024		—		680,213		719,399		76,140		3,178,930
	2008		694,230	—			2,613,292		—		750,000		642,938		272,727		4,973,187
	2007		558,000	—			3,160,541		—		577,536		442,503		158,029		4,896,609

McLean	2009		640,346	—			651,160		—		437,276		122,086		87,738		1,938,606
	2008		561,538	—			2,155,848		—		510,416		95,727		216,544		3,540,073
	2007		482,500	—			2,100,491		—		403,276		53,160		96,874		3,136,301

Moler	2009		482,692	—			792,401		—		282,270		40,181		76,253		1,673,797
	2008		484,615	—			1,175,408		—		329,000		333,981		195,611		2,518,615

Pardee	2009		568,615	16,903			440,620		—		338,052		221,082		33,192		1,618,464
	2008		525,289	44,000			1,703,768		—		484,000		213,293		164,619		3,134,969
	2007		426,308	—			1,219,619		—		350,277		110,591		69,591		2,176,386

Cornew	2009		391,308	11,172			261,238		—		223,447		99,877		17,175		1,004,217

Adams	2009		330,339	16,515			206,668		—		165,152		190,121		4,100		912,895
	2008		320,000	—			753,840		—		175,973		72,722		86,772		1,409,307
	2007		305,008	—			542,053		—		222,621		74,219		10,602		1,154,503

Bonney	2009		284,586	—			144,262		—		121,482		337,150		14,840		902,320
	2008		273,020	25,000			316,456		—		120,951		130,060		74,953		940,440

Acevedo	2009		212,208	3,695			84,385		—		73,899		33,958		10,610		418,755

Galvanoni	2009		220,828	3,934			74,067		—		78,689		37,458		11,520		426,496
	2008		214,462	(4,854	)		158,228		—		92,213		23,908		66,284		550,241
	2007		199,603	—			473,259		—		119,096		20,969		12,707		825,634

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ComEd

Compensation Actually Paid to NEOs

(Equity Valued at Actual Value on Award Date Instead of Grant Date Fair Value)


Name and Principal Position (A)	Year (B)	Salary ($) (C)		Bonus ($) (D)	Stock Awards Valued at Award Date ($) (E)		Value of In the Money Stock Options at 1/25/2010 ($) (F)		Non-Equity Incentive Plan Compensation ($) (G)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($) (H)		All Other Compen- sation ($) (I)		Total ($) (J)
Clark	2009	$	564,385	—	$	254,300	$		$	1,461,250	$	180,950	$	85,888	$	2,546,773
	2008		546,692	—						2,049,371		548,986		193,738		3,338,787
	2007		474,231	—		370,500				2,288,853		391,782		146,412		3,671,778

Trpik	2009		263,810	6,300		43,417		—		257,556		51,563		27,312		649,958

McDonald	2009		309,262	—						421,841		1,628,897		944,037		3,304,037
	2008		336,038	—						789,747		304,534		144,201		1,574,520
	2007		310,600	100,000						887,688		225,879		74,566		1,598,733

Pramaggiore	2009		391,269	24,900						776,342		89,876		33,774		1,316,161
	2008		348,500	20,295						817,247		49,083		127,421		1,362,546
	2007		290,154	150,000		326,560				347,222		36,593		43,225		1,193,754

Hooker	2009		321,923	159,075						499,500		172,435		46,885		1,199,818
	2008		307,692	9,007						657,135		474,488		128,861		1,577,183
	2007		277,231	150,000		326,560				695,830		283,124		65,433		1,798,178

Donnelly	2009		326,154	9,625						574,610		134,917		35,392		1,080,698

Mitchell	2009		471,846	—						998,400		1,517,123		77,702		3,065,071
	2008		477,692	—						1,402,448		571,280		197,955		2,649,375
	2007		437,477	—		408,200				1,592,848		736,464		138,596		3,313,585

Reductions in Compensation for 2010

Because of the earnings challenges Exelon faces in 2010, the compensation committee and the Exelon and ComEd boards of directors have taken the following actions to reduce compensation in 2010 and achieve approximately $150 million in savings:

•

Freezing salaries for executives;

•

Recalibrating the annual incentive program payout scale to reduce the threshold payout from 50% to 25% and reduce the target payout from 100% to 50%, while leaving distinguished payout at 200% (this is expected to result in approximately $100 million of the savings);

•

Enhancing shareholder protection features in the annual incentive plan by limiting key performance indicator payouts to no more than 10% above the earnings payout percentage;

•

Reducing the target values for long-term incentives by about 33%; and

•

Reducing the company fixed match on 401(k) contributions from 5% to 3% of base salary, with the potential for a formula-based profit sharing contribution of up to an additional 3% of base salary.

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As an example of the results of these actions, Mr. Rowe’s 2010 long term equity incentive compensation has been reduced relative to 2009. Mr. Rowe received the following stock option grants and performance share grants and awards for 2009 and 2010:

Stock Options


Shares Granted	Value			Based on:
2009 155,000 @ strike price of $56.51	$	2,236,650		Grant Date Fair Value
2010 138,000 @ strike price of $46.09		1,115,040		Estimated Grant Date Fair Value

Change in Grant Value from 2009 to 2010 =	$	(1,121,610	)

Performance Shares


Shares Granted	Value			Based on:
2009 69,700 (upon Grant)	$	6,341,383		Grant Date Fair Value
58,966 (upon Award)		2,717,743		Actual Value on Award Date
2010 54,000 (upon Grant)		1,070,210		Estimated Grant Date Fair Value

Change in Grant Value from 2009 to 2010 =	$	(5,271,173	)

Reduced Value of Accumulated Wealth from Incentive Compensation Programs

Exelon’s executive compensation program links the wealth that the named executive officers accumulate from their Exelon compensation to the company’s future financial performance by paying a substantial portion of incentive compensation in the form of Exelon equity. As a result of this policy, in addition to the reductions in their compensation that have resulted from Exelon’s lower financial performance, Exelon’s NEOs have experienced significant reductions in their accumulated wealth because the value of Exelon’s equity has declined since the price of Exelon’s common stock peaked at $91.64 on July 10, 2008. The following table shows the value of Mr. Rowe’s holdings of Exelon equity at December 31 2007, 2008 and 2009; the other NEOs have experienced proportional reductions in the value of their Exelon equity:


Name	Date: December 31,	Number of Vested Shares of Exelon Common Stock Note ⁽¹⁾	Value of Vested Shares of Exelon Common Stock		Number of Vested and Unvested Stock Options Note ⁽²⁾	Value of Vested and Unvested Stock Options		Number of Unvested Performance Share Awards and Unvested Restricted Stock Awards	Value of Unvested Portion of Performance Share Awards and Unvested Restricted Stock Awards		Total Value
Rowe	2009	311,368	$	15,216,554	648,000	$	1,378,580	115,429	$	5,641,015	$	22,236,149
	2008	309,985		17,238,266	493,000		2,922,040	127,338		7,081,266		27,241,572
	2007	337,514		27,554,643	379,000		12,134,910	116,753		9,529,266		49,218,819

(1)

Vested shares held include shares held directly and through the Employee Stock Purchase Plan, the 401(k) plan, and share equivalents held in the deferred compensation plan. During 2008, Mr. Rowe’s holdings increased by 51,317 shares as the result of options exercised through Rule 10b5-1 Sales Plans entered into in August 2006 and September 2007, offset by his donation of 80,000 shares to a charitable trust in November 2008 pursuant to another Rule 10b5-1 Sales Plan entered into in May 2008.

(2)	During 2008, Mr. Rowe exercised 550,000 options pursuant to Rule 10b5-1 Sales Plans as described in the note above. These options have been omitted from the 2007 balance that is shown.

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Elimination of Future Excise Tax Gross-ups on Termination Payments

In 2009 there were no significant changes to the design of Exelon’s executive compensation program, except that in April 2009 the compensation committee adopted a policy that future employment or severance agreements that provide for benefits for NEOs on account of termination will not include an excise tax gross-up. The policy is more fully described below under Other Benefits—Change In Control and Severance Benefits. On October 27, 2009, the board of directors approved the Third Amended and Restated Employment Agreement with Mr. Rowe. In the agreement, Mr. Rowe’s previous excise tax gross-up benefit was eliminated consistent with the policy. The agreement is more fully described below under Potential Payments upon Termination or Change in Control—Employment Agreement with Mr. Rowe.

Objectives of the Compensation Program

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 vision of being the best group of electric generation and electric and gas delivery companies in the United States, providing superior value for Exelon’s customers, employees, investors and the communities Exelon serves. 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. The 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. 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 have value only to the extent that Exelon’s stock price increases following the option grant date. As a result of the performance-based features of his cash and equity-based compensation, 82% of Mr. Rowe’s 2009 target total direct compensation (base salary plus annual and long-term incentive compensation) was at-risk. Similarly, of the other NEOs’ 2009 target total direct compensation, approximately 49% to 75% was at-risk.

Recoupment Policy

Consistent with the pay-for-performance policy, in May 2007 the board of directors adopted a recoupment policy as part of Exelon’s corporate governance principles. The board of directors will seek recoupment of incentive compensation paid to an executive officer if the board determines, in its sole discretion, that

•

the executive officer engaged in fraud or intentional misconduct;

•

as a result of which Exelon was required to materially restate its financial results;

•

the executive officer was paid more incentive compensation than would have been payable had the financial results been as restated;

•

recoupment is not precluded by applicable law or employment agreements; and

•

the board concludes that, under the facts and circumstances, seeking recoupment would be in the best interest of Exelon and its shareholders.

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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. Equity-based compensation is in the form of performance share units, stock options, and restricted stock units that are valued in relation to Exelon’s common stock, and they gain value in relation to the market price of Exelon’s stock or Exelon’s total shareholder return in comparison to other energy services companies and/or general industry. Conversely, when the market price of Exelon’s stock decreases, the value of the equity compensation decreases.

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 generally 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.

Each year the compensation committee commissions its consultant to prepare a study to benchmark total direct compensation against a peer group of companies. The study 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. All competitive data was aged to January 2009 using a 3.70% annual update factor. The study indicated that a steady state was appropriate, with an average of 4% increases to base salaries and relatively unchanged targets for annual and long-term incentives, and that no changes were needed for the long-term incentive mix and design. The consultant considered Exelon’s organizational changes to determine how Exelon’s positions compared with positions at its peers by establishing a benchmark match for each Exelon executive in the competitive market, where available, and reviewed each element of compensation as well as total direct compensation.

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The peer group criteria include having revenue similar to Exelon’s $19 billion, 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 Database. The peer group was the same in 2009 as it was in 2008, except that for 2009 Energy Future Holdings, which is no longer publicly traded, was replaced by FPL Group because it met the criteria with revenues similar to Exelon’s and is another energy services company. The peer group includes the following companies:


General Industry Companies	FY 2008 Revenue ($ Million)		FY 2008 Total Assets ($ Million)		October 2009 Market Cap ($ Million)
3M	$	25,269	$	25,547	$	52,084
Abbott Laboratories		29,528		42,419		78,177
Caterpillar Inc.		51,324		67,782		34,287
General Mills Inc.		14,691		17,875		21,510
Hess Corporation		41,165		28,589		17,903
Honeywell International		36,556		35,490		27,386
International Paper		24,829		26,913		9,649
Johnson Controls Inc.		38,062		24,987		14,243
PepsiCo Inc.		43,251		35,994		94,397
PPG Industries, Inc.		15,849		14,698		9,423
Union Pacific Corp.		17,970		39,722		27,820
Weyerhaeuser Company		8,018		16,735		7,681

Energy Services Companies
American Electric Power	$	14,440	$	45,155	$	14,427
Centerpoint Energy		11,322		19,676		4,918
Dominion Resources, Inc.		16,290		42,053		20,360
Duke Energy Corp.		13,207		53,077		20,613
Edison International		14,112		44,615		10,367
Entergy Corp.		13,094		36,617		14,492
FirstEnergy Corp.		13,580		33,521		13,193
FPL Group		16,410		44,821		20,203
PG&E Corp.		14,628		40,860		15,165
Public Service Enterprise Group		13,807		29,049		15,078
Southern Co.		17,127		48,347		24,829
Xcel Energy, Inc.		11,203		24,958		8,605
Exelon	$	18,859	$	47,817	$	30,947

The compensation committee generally applies the same policies with respect to the compensation of each of the individual NEOs. The compensation committee carefully considers the roles and responsibilities of each of the NEOs relative to the peer group, as well as the individual’s performance and contribution to the performance of the business in establishing the compensation opportunity for each NEO. The differences in the amounts of compensation awarded to the NEOs reflect primarily two factors, the differences in the compensation paid to officers in comparable positions in the peer group and differences in the individual responsibility and experience of the Exelon officers. Time in position affects where individuals are relative to market percentiles, with cash compensation generally at the median and incentive compensation slightly above the median. The nuclear organization’s pay is generally closer to the 75^th percentile given the size and quality of Exelon’s nuclear fleet, and certain positions are at the 75^th percentile because of unusual expertise in

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regulatory or nuclear matters. The delivery company presidents were evaluated as a blend of top energy delivery executives and freestanding CEOs, given the amount of independence they have. Mr. Rowe’s target compensation was based on the same factors as the other NEOs, but his compensation reflected a greater degree of policy and decision-making authority and a higher level of responsibility with respect to strategic direction and financial and operating results of Exelon. His target compensation was assessed relative to other CEOs in the peer group. Mr. Rowe’s compensation also reflects the fact that Exelon has the largest market capitalization in the industry and that Exelon has the largest nuclear fleet in the industry. It also reflects that Mr. Rowe is the senior CEO in the industry.

The role of individual performance in setting compensation

While the consideration of benchmarking data to assure that Exelon’s compensation is competitive is a critical component of compensation decisions, individual performance is factored into the setting of compensation in three ways:

•

First, base salary adjustments are based on an assessment of the individual’s performance in the preceding year as well as a comparison with market data for comparable positions in the peer group.

•

Second, annual incentive targets are based on the individual’s role in the enterprise—the most senior officers with responsibilities that span specific business units or functions have a target based on earnings per share for the company as a whole, while individuals with specific functional or business unit responsibilities have a significant portion of their targets based on the performance of that functional or business unit.

•

Third, consideration is given as to whether an individual performance multiplier would be appropriately applied to the individual’s annual incentive plan award, based on the individual’s performance. The individual performance multiplier can result in a decision not to make an award or to decrease the amount of the award or to increase the amount of the award by up to 10% so long as the adjusted award does not exceed the maximum amount that could be paid to the executive based on achievement of the objective performance criteria applicable under the plan.

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 2009 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. For all NEOs other than those at ComEd, approximately 37% to 68% of NEOs’ total target direct compensation is delivered in the form of cash and equity compensation accounts for approximately 32% to 63% of NEO total target direct compensation. For ComEd NEOs, all total target direct compensation is delivered in the form of cash and there is no equity component, consistent with continuing efforts to recognize ComEd’s independence and to maximize recovery in rates. 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.

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Base Salary

Exelon’s compensation program for NEOs is designed so that approximately 18% to 51% of NEO total direct compensation is in the form of base salary, consistent with practices at the companies in the peer group.

Annual Incentives

Annual incentive compensation 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 made to NEOs and other employees if, and only to the extent that, performance conditions set by the compensation committee are met.

Long-term Incentives

Long-term incentives are made available to executives and key management employees who affect the long-term success of the company. The long-term incentive compensation programs are primarily equity based and designed to provide incentives and rewards closely related to the interests of Exelon’s shareholders, generally as measured by the performance of Exelon’s total shareholder return and stock price appreciation.

A portion of the long-term incentive compensation is in the form of performance share units that are awarded only 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 that provide value only if, and to the extent that, the market price of Exelon’s common stock increases following the grant. The use of both forms of long-term incentives is consistent with the practices in our peer group. The mix of long-term incentives depends on the compensation committee’s assessment of competitive compensation practices of companies in the peer group.

Stock option repricing is prohibited by policy or the terms of the company’s long-term incentive plans. Accordingly, no options have been repriced. Stock option awards are generally granted annually 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. Only two off-cycle grants of stock options were made in 2009, in each case to an officer beginning employment during the year.

In 2007, consistent with the continuing efforts to recognize ComEd’s independence, the compensation committee recommended, and the ComEd board adopted, a separate long-term incentive program for ComEd’s executives for the period 2007-2009. The goals under the ComEd long-term incentive program are the achievement of ComEd financial, operational, and regulatory/legislative goals. Payments under this plan are made in cash, and are awarded annually by the ComEd board based on the assessment of performance during the year. Other features of the program are similar to the Exelon performance share award program, including the payout of awards ranging from 0-200% of target and vesting over three years.

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. However, in 2007 the compensation committee terminated the stock ownership requirements for ComEd officers in light of the continuing efforts to

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recognize ComEd’s independence and the compensation committee’s recommendation that ComEd officers participate in a separate cash-based long-term incentive program instead of receiving Exelon performance shares. 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.

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. Many of the NEOs have such plans, and their exercises during 2009 are reflected in the “Option Exercises and Stock Vested” table below. 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.

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 to continue to work in the best interests of shareholders, notwithstanding any concern they might have 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.

In 2007, the compensation committee adopted a policy limiting the amount of future severance benefits to be paid to NEOs under future arrangements without shareholder approval to 2.99 times salary plus annual incentive. This policy clarifies that severance benefits include cash severance payments and other post-employment benefits and perquisites, but do not include:

•

Amounts earned in the ordinary course of employment rather than upon termination, such as pension benefits and retiree medical benefits;

•

Amounts payable under plans approved by shareholders;

•

Amounts available to one or more classes of employees other than the NEOs;

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•

Excise tax gross-up payments, but only if the compensation includable in determining whether excise taxes apply exceed 110% of the threshold amount; otherwise the NEO’s benefits are reduced so that no excise tax is imposed; and

•

Amounts that may be required by existing agreements that have not been materially modified, Exelon’s indemnification obligations or the reasonable terms of a settlement agreement.

In April 2008, the compensation committee reviewed the level of non-change in control severance benefits provided to senior vice presidents. These benefits had varied over time as the corporate organization evolved within a range of 1.25 to 2 times annual salary and incentive. The compensation consultant reported that 1.5 times annual salary and incentive was more appropriate and consistent with competitive practices. The compensation committee determined that non-change in control severance benefits for senior vice presidents would be reset at 1.5 times annual salary and bonus, provided that those senior vice presidents with such benefits at 2 times annual salary and bonus would be grandfathered at that level. In December 2008, the individual change in control employment agreements provided to the NEOs (other than the CEO) and certain other executives were amended to comply with section 409A of the Internal Revenue Code, which requires that certain payments of deferred compensation be paid not earlier than six months following a termination of employment. In addition, the severance multiple available to executives who entered into such agreements prior to 2007 was reduced from 3.0 to 2.99 times base salary and annual incentive, consistent with the 2007 compensation committee policy described immediately above, and the board’s recoupment policy was incorporated.

In April 2009, the compensation committee adopted a policy that no future employment or severance agreement that provides for benefits for NEOs on account of termination will include an excise tax gross-up. The policy applies to employment, change in control, severance and separation agreements entered into, adopted, or materially changed on or after April 2, 2009, other than agreements changed to comply with law or to reduce or eliminate rights, agreements assumed in a corporate transaction, and automatic extensions or renewals where other terms are not changed. The compensation committee has the sole and absolute power to interpret and apply the policy, and it can amend, waive or terminate it if in the best interest of the company, provided that prompt disclosure is made.

Retirement Benefit Plans

The compensation committee believes that retirement benefit plans are an important part of the NEO compensation program. These plans serve a critically important role in the retention of senior executives, as retirement benefits 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. Exelon sponsors both qualified traditional defined benefit and cash balance defined benefit pension plans and related non-qualified supplemental pension plans (the SERPs).

Exelon previously granted additional years of credited service under the SERP to a few executives in order to recruit or retain them. 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 were not affected by this policy. To attract a new executive, Exelon is permitted to grant additional years of

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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.

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. In 2005, the compensation consultant reviewed Exelon’s perquisites program. Although specific data for Exelon’s peer group was not available, the compensation consultant based its analysis on survey data for large energy and general industry companies. The compensation consultant 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.

Anticipating an emerging trend among the peer group to curtail perquisite programs in the future, on January 22, 2007 the compensation committee approved the phase-out of many executive perquisites, effective January 1, 2008. The eliminated perquisites included: leased vehicles (existing leases allowed to expire), financial and estate planning, tax preparation and health and dining/airline club memberships.

How The Amount of 2009 Compensation Was Determined

This section describes how 2009 compensation was determined and awarded to the NEOs.

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 2009. 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, efficiency, and the environment,

•

supporting competitive markets,

•

protecting the value of our generation assets, and

•

building healthy, self-sustaining delivery companies; as well as

goals relating to growing long-term value, including:

•

organizational improvement,

•

advancing an environmental strategy that sets the industry standard for low carbon energy generation and delivery, and

•

rigorously evaluating new growth opportunities.

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The Exelon board considered, in particular, strong operational results. Outage frequency and duration improved at the energy delivery companies, with ComEd’s outage results being its best ever, and the average capacity factor of the nuclear generating plants was also high, with 2009 being the seventh consecutive year with capacity factor above 93%. While operating earnings declined as a result of the continued economic turmoil, lower demand, poor power prices, unfavorable weather, and higher pension and post-retirement benefit costs, the cost management initiative was clearly successful. The board also considered 2009 progress in advancing longer-term goals, including efforts to promote pragmatic strategies for addressing climate change, progress in the Exelon 2020 strategy, including outperforming on the carbon dioxide reduction commitment and being on track on all other 2020 initiatives, the launching of a less expensive and lower risk strategy to expand nuclear generation through uprating Exelon’s existing nuclear plants, the initiation of two transmission initiatives, establishing Exelon Transmission Company and working to address transmission constraints that suppress prices for the output of the nuclear plants in the Midwest, and progress on smart grid initiatives at ComEd and PECO. The board also considered progress in talent development, diversity, and the corporate culture.

How base salary was determined

At its January 26, 2009 meeting, the compensation committee reviewed base salary data for the NEOs listed in the Summary Compensation Table as compared to compensation data at the 50^th and 75^th percentile of the peer group. Based on this review and their individual performance reviews, including the review of Mr. Rowe’s performance by the corporate governance committee and the independent directors, the NEOs received base salary increases effective as of March 1, 2009 that ranged from 3% to 5%, with the overwhelming majority of the increases ranging from 3% to 4%, and only three exceeding 4%. These increases were consistent with the average 4% increase that the consultant reported was competitive.

In April 2009 Messrs. J. Barry Mitchell, ComEd’s President and Chief Operating Officer, and Robert K. McDonald, ComEd’s Senior Vice President and Chief Financial Officer, announced their planned retirements and the compensation committee recommended, and the ComEd board approved, compensation adjustments in connection with the additional responsibilities assumed by certain officers as a result of promotions under the reorganization of ComEd’s management structure that ensued from the retirements. These adjustments took effect on May 11, 2009. Anne R. Pramaggiore was promoted to President and Chief Operating Officer. Terence R. Donnelly was promoted to Executive Vice President, Operations. John T. Hooker was promoted to Executive Vice President, Legislative and External Affairs.

In June 2009 Exelon’s executive leadership organizational structure was reorganized. In July 2009, the compensation committee recommended, and the board of directors approved, compensation adjustments in connection with the additional responsibilities assumed by certain officers as a result of promotions under the reorganization. In addition, the compensation committee recommended, and the ComEd board approved, an increase in compensation for Mr. Joseph R. Trpik, Jr., who had been appointed interim Chief Financial Officer of ComEd in the May 2009 reorganization and was appointed Senior Vice President, Chief Financial Officer and Treasurer of ComEd effective July 6, 2009. These increases were based on the compensation committee’s determination that the compensation for these officers in their new roles was not competitive, as evidenced by market comparisons with the peer group prepared by the compensation committee’s consultant using the same methodology used for annual adjustments. These base salary adjustments were effective as of August 3, 2009.

Messrs. Acevedo, Galvanoni, and Bonney received base salary increases in June, August and December, 2009, respectively, in connection with their assuming additional responsibilities.

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The amounts of base pay, percentages of increase, and effective dates of base salary increases are set forth in the following table.

Exelon, Generation and PECO


Name	Base Salary		Percent Increase		Effective Date
Rowe	$	1,475,000	3.1	%	3/1/2009
O’Brien		536,000	3.1		3/1/2009
Hilzinger		446,000	4.9		3/1/2009
Barnett		309,900	3.3		3/1/2009
Crane		825,000	3.1		3/1/2009
McLean		644,000	3.0		3/1/2009
Moler		485,000	3.2		3/1/2009
Pardee		572,000	4.0		3/1/2009
Cornew		394,000	3.7		3/1/2009
Adams		332,800	4.0		3/1/2009
Bonney		285,928	4.0		3/1/2009
Bonney		306,000	7.0		12/7/2009
Acevedo		211,926	4.5		3/1/2009
Acevedo		216,000	1.9		6/22/2009
Galvanoni		216,320	4.0		3/1/2009
Galvanoni		230,000	6.3		8/3/2009

ComEd


Name	Base Salary		Percent Increase		Effective Date
Clark	$	567,000	3.1	%	3/1/2009
Trpik		254,550	4.0		3/1/2009
Trpik		280,000	10.0		8/3/2009
McDonald		336,000	3.1		3/1/2009
Pramaggiore		353,200	4.5		3/1/2009
Pramaggiore		415,000	17.5		5/11/2009
Hooker		312,000	4.0		3/1/2009
Hooker		330,000	5.8		5/11/2009
Donnelly		286,000	4.0		3/1/2009
Donnelly		350,000	22.4		5/11/2009
Mitchell		474,000	3.0		3/1/2009

How 2009 annual incentives were determined

For 2009, 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 2009 operating income, the same percentage used in 2008 and 2007, but was not fully distributed to participants because the committee decided on substantially lesser awards.

Annual incentive payments for 2009 to Messrs. Rowe, O’Brien, Crane, McLean, Clark, Pardee, and Mitchell and Ms. Moler 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 unusual or non-recurring items.

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For executives with general corporate responsibilities, the goal was adjusted (non-GAAP) operating earnings per share so that they would focus their efforts on overall corporate performance. The earnings per share goal ranges were set to be like the forecast earnings ranges, with the annual incentive plan target the same as the financial plan target. In accordance with the design of the annual incentive program, the compensation committee reviewed 2009 earnings and decided not to include the effects of significant one-time charges or credits that are not normally associated with ongoing operations and mark-to-market adjustments from economic hedging activities in adjusting earnings for purposes of making awards under the annual incentive plan. The adjusted earnings are consistent with the adjusted (non-GAAP) operating earnings that Exelon reports in its quarterly earnings releases. For 2009, the adjustments included:

•

the cost of Illinois rate relief associated with the legislative settlement and a settlement with the City of Chicago,

•

unrealized gains and losses on mark-to-market adjustments,

•

a reduction in estimated decommissioning costs,

•

incremental costs associated with the proposed NRG transaction,

•

certain non-cash income tax benefits,

•

severance costs,

•

costs of a debt tender and refinancing, and

•

charges associated with the impairment or retirement of certain generating assets.

2009 annual incentive payments for other NEOs with specific business unit responsibilities were based upon a combination of adjusted (non-GAAP) operating 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 (so they would focus on the performance of their business unit). Under the terms of the plan, the business unit financial measures are adjusted from GAAP measures. For ComEd executive officers, adjusted (non-GAAP) operating earnings of Exelon were not a goal, consistent with the continuing efforts to recognize ComEd’s independence as described above. ComEd’s goals included other financial and operational goals. PECO’s financial measures were slightly adjusted, as compared to 2008, to better align them with ComEd’s goals. The following table summarizes the goals and weights applicable to the NEOs for 2009:

Exelon, Generation and PECO


Name	Adjusted Operating Earnings Per Share		Adjusted Generation Net Income		Adjusted PECO Net Income		Exelon Nuclear Fleet- Wide Capacity Factor		Adjusted PECO Total Cost		Adjusted BSC Total Cost		PECO Reliability, Safety, Customer Satisfaction Measures & Focused Initiatives
Rowe	100	%	—	%	—	%	—	%	—	%	—	%	—	%
O’Brien	50		—		20		—		—		—		30
Hilzinger	75		—		—		—		—		25		—
Barnett	25		—		20		—		25		—		30
Crane	100		—		—		—		—		—		—
McLean	100		—		—		—		—		—		—
Moler	100		—		—		—		—		—		—
Pardee	50		25		—		25		—		—		—
Cornew	50		50		—		—		—		—		—
Adams	25		—		20		—		25		—		30
Bonney	25		—		20		—		25		—		30
Acevedo	75		—		—		—		—		25		—
Galvanoni	75		—		—		—		—		25		—

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ComEd


Name	Adjusted ComEd Net Income		Adjusted ComEd Total Capital Expenditures		Adjusted ComEd Total O&M Expense		ComEd Reliability, Safety, Customer Satisfaction Measures & Focused Initiatives
Clark	25	%	12.5	%	12.5	%	50	%
Trpik	25		12.5		12.5		50
McDonald	25		12.5		12.5		50
Pramaggiore	25		12.5		12.5		50
Hooker	25		12.5		12.5		50
Donnelly	25		12.5		12.5		50
Mitchell	25		12.5		12.5		50

The following table describes the performance scale and result for the 2009 goals:

Exelon, Generation, and PECO


2009 Goals	Threshold			Target			Distinguished			2009 Results			Payout as a Percentage of Target
Adjusted (non-GAAP) Operating Earnings Per Share (EPS)	$	3.65		$	4.15		$	4.45		$	4.12		97.00	%
Adjusted Generation Net Income ($M)	$	2,010		$	2,160		$	2,260		$	2,092.5		77.50	%
Adjusted PECO Net Income ($M)	$	275		$	334		$	360		$	350.63		163.95	%
Exelon Nuclear Fleet-Wide Capacity Factor		91.1	%		93.1	%		93.8	%		93.6	%	171.43	%
Adjusted PECO Total Cost ($M)	$	912.03		$	868.60		$	842.55		$	790.88		200.00	%
Adjusted BSC Total Cost ($M)	$	668.7		$	636.9		$	617.8		$	576.4		200.00	%
PECO Reliability Measure—Customer Average Interruption Duration Index (CAIDI) (minutes per outage)		96			90			87			90		100.00	%
PECO Reliability Measure—System Average Interruption Frequency Index (SAIFI) (outages per customer)		1.08			0.85			0.76			0.80		155.56	%
PECO Reliability Measure—Gas All-In Corrective Maintenance Backlog (year-end number of tasks)		500			475			450			422		200.00	%
PECO Safety Measure—Occupational Safety and Health Administration (OSHA) Recordable Rate		1.68			1.05			0.95			1.45		68.25	%
PECO Customer Satisfaction (weighted combined score of residential, small commercial & industrial and large commercial & industrial customers)		77			79			81			81.6		200.00	%
PECO Focused Initiatives		90	%		100	%		105	%		105	%	200.00	%

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ComEd


2009 Goals	Threshold			Target			Distinguished			2009 Results			Payout as a Percentage of Target
Adjusted ComEd Net Income ($M)	$	298.6		$	345.0		$	365.0		$	355.6		152.95	%
Adjusted ComEd Total Capital Expenditures ($M)	$	762.2		$	725.9		$	704.1		$	714.5		152.53	%
Adjusted ComEd Total O&M Expense ($M)	$	680.9		$	648.4		$	629.0		$	602.7		200.00	%
ComEd Reliability Measure—CAIDI (minutes per outage)		96			87			84			84		200.00	%
ComEd Reliability Measure—SAIFI (outages per customer)		1.13			1.03			0.99			0.86		200.00	%
ComEd Safety Measure—OSHA Recordable Rate		1.30			1.13			1.08			1.04		200.00	%
ComEd Customer Satisfaction (weighted combined score of residential, small commercial & industrial and large commercial & industrial customers)		77			79			81			80.5		175.00	%
ComEd Focused Initiatives		90	%		100	%		105	%		113	%	200.00	%

The 2009 annual incentive program included the following shareholder protection features (SPF):

•

If target earnings per share are not achieved, then operating company/business unit key performance indicator payments are limited to actual performance, not to exceed 100% of the target payout

•

If earnings per share are greater than or equal to target, but less than 150% of target, then the operating company/business unit key performance indicator payments are limited to 150% of target payout

•

If earnings per share are greater than or equal to 150% of target, operating company/business unit key performance indicators are based on actual performance.

As a result of 2009 earnings being at 97% of target, the operating company/business unit key performance indicators were limited to actual performance, not to exceed 100% of target. The effect of these SPF reductions is shown in the table below.

In making annual incentive awards, the compensation committee has the discretion to reduce or not pay awards even if the targets are met. The compensation committee recommended, and the ComEd board of directors approved, a capping of ComEd awards at target (100%) in order that the annual incentive compensation paid at Exelon’s operating companies be roughly equal.

With respect to the NEOs in the table below, individual performance multipliers (IPM) other than 100% were approved and recommended by the compensation committee based upon assessments of NEO 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. Increases in IPM shown below reflect exceptional performance.

Based on the performance against the goals shown in the tables above, and taking into account the reductions resulting from the shareholder protection features and the caps and adjustments discussed above, the compensation committee recommended and the Exelon or the ComEd board of

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directors, as the case may be (or in the case of Mr. Rowe, the independent directors) approved the following awards for the NEOs:


Exelon, Generation, and PECO	Payout as a % of Target (pre-SPF)		Payout $ (pre-SPF)		SPF Reduction $			Payout as a % of Target (post-SPF & pre-IPM)		Payout $ (post-SPF & pre-IPM)		IPM %		Payout $ (post-SPF & post-IPM)
Rowe	97.0	%	$	1,573,825	$	—		97.0	%	$	1,573,825	100	%	1,573,825
O’Brien	127.5			512,475		(116,505	)	98.5			395,970	100		395,970
Hilzinger	122.8			328,479		(66,900	)	97.8			261,579	105		274,658
Barnett	153.2			237,432		(83,644	)	99.3			153,788	100		153,788
Crane	97.0			680,213		—		97.0			680,213	100		680,213
McLean	97.0			437,276		—		97.0			437,276	100		437,276
Moler	97.0			282,270		—		97.0			282,270	100		282,270
Pardee	110.7			380,033		(41,981	)	98.5			338,052	105		354,955
Cornew	87.3			223,447		—		87.3			223,447	105		234,620
Adams	153.2			254,977		(89,825	)	99.3			165,152	110		181,667
Bonney	153.2			187,555		(66,073	)	99.3			121,482	100		121,482
Acevedo	122.8			92,799		(18,900	)	97.8			73,899	105		77,594
Galvanoni	122.8			98,814		(20,125	)	97.8			78,689	105		82,623

ComEd	Payout as a % of Target (pre-CEO Discretion)		Payout $ (pre-CEO Discretion)		CEO Discretion Reduction $			Payout as a % of Target (pre-IPM)		Payout $ (pre-IPM)		IPM %		Payout $ (post-IPM)
Clark	179.8	%	$	764,613	$	(339,363	)	100	%	$	425,250	100	%	425,250
Trpik	179.8			226,552		(100,552	)	100			126,000	105		132,300
McDonald	179.8			225,931		(100,276	)	100			125,655	100		125,655
Pramaggiore	179.8			447,710		(198,710	)	100			249,000	110		273,900
Hooker	179.8			326,343		(144,843	)	100			181,500	105		190,575
Donnelly	179.8			346,121		(153,621	)	100			192,500	105		202,125
Mitchell	179.8			511,360		(226,960	)	100			284,400	100		284,400

How long-term incentives were determined

The compensation committee reviewed the amount of long-term compensation paid in the peer group for positions comparable to the positions held by the NEOs and then applied a ratio of stock options to performance shares in order to determine the target long-term equity incentives for each NEO, using Black-Scholes valuation for stock options and a 90 day weighted-average price for the preceding quarter to value performance shares. Stock option grants for 2009 were all at the targeted amounts. The actual amounts of performance shares awarded to the NEOs depended on the extent to which the performance measures were achieved.

Stock option awards

The company granted non-qualified stock options to the Exelon Corporation senior officers, including the NEOs, but excluding the ComEd NEOs, on January 26, 2009. The stock option grants for 2009 were all at the targeted amounts. These options were awarded at an exercise price of $56.51, which was the closing price on the January 26, 2009 grant date. The number of the option awards granted in 2009 was larger than in 2008, reflecting the decrease in the price of Exelon’s stock on the grant date in 2009 as compared to the price on the grant date in 2008.

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Exelon performance share unit awards

The 2009 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). This structure was consistent with the structure used in the 2008 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 fell below target performance levels with respect to both TSR measures. For the performance period of January 1, 2007 through December 31, 2009, Exelon’s relative ranking of TSR as compared to the Dow Jones Utility Index was at the 37.5 percentile ranking or 75% of target payout. For the same time period, the company’s relative ranking of TSR in the S&P 500 Index was at the 49.5 percentile ranking or 99.1% of target payout. Overall performance against both measures combined resulted in a payout to participants for 2009 that represented 84.6% of each participant’s target opportunity.

The amount of each NEO’s target opportunity was based on the portion of the long-term incentive value for each NEO attributable to performance share units (75%) and the weighted average Exelon stock price for the fourth quarter of 2008.

Based on the formula, 2009 Performance Share Unit Awards for NEOs were as set forth in the following table. The first third of the awarded performance shares vests upon the award date, with the remaining thirds vesting on the date of the compensation committee’s January meeting in the next two years.


Exelon, Generation, and PECO	Shares	Value *		Form of Payment **
Rowe	58,966	$	2,717,743	100% Cash
O’Brien	11,675		538,101	100% Cash
Hilzinger	5,668		261,238	50% Cash /50% Stock
Barnett	3,553		163,758	50% Cash /50% Stock
Crane	19,137		882,024	100% Cash
McLean	14,128		651,160	100% Cash
Moler	11,675		538,101	100% Cash
Pardee	9,560		440,620	50% Cash /50% Stock
Cornew	5,668		261,238	50% Cash /50% Stock
Adams	4,484		206,668	50% Cash /50% Stock
Bonney	3,130		144,262	50% Cash /50% Stock
Acevedo	850		39,177	100% Stock
Galvanoni	1,607		74,067	50% Cash /50% Stock
Trpik***	942		43,417	100% Cash

*	Based on the Exelon closing stock price of $46.09 on January 25, 2010.

**	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.

***	Mr. Trpik received a pro-rated performance share unit award for the period that he was an Exelon officer before becoming an officer of ComEd.

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2007-2009 ComEd Long-Term Incentive Program

In 2007 the compensation committee recommended, and the ComEd board adopted, a long-term incentive program designed to align the incentive compensation program with ComEd’s status as a fully regulated operating company. Accordingly, the program pays out in cash; there is no Exelon equity component to the program. The program for the 2007-2009 performance period is based on ComEd’s executive’s ability to avoid adverse legislation and maintain competitive power procurement with cost pass through as well as make appropriate progress in ComEd’s 2007-2011 business plan. The measures are qualitative and quantitative and encompass financial (one-third), operational (one-third), and regulatory and legislative (one-third) goals for the three-year target. There is a subjective element to payouts under the program. Financial goals for the performance cycle are that by year-end 2009, ComEd’s 2010 budget should reflect financial stability as evidenced by financial measures such as an industry median, adjusted (non-GAAP) operating return on equity, with the milestone for year-end 2009 being an adjusted (non-GAAP, e.g., excluding goodwill) return on equity at 8.3% with 55% debt; the threshold for this milestone is 7.2%, with distinguished at 8.8%. Operational goals are measured by ComEd CAIDI and ComEd SAIFI. The performance cycle goals are to achieve second quartile (or the level agreed to with the Illinois Commerce Commission) with targets of 1.15 and 92, respectively. The 2009 milestone is SAIFI of 1.03, with threshold at 1.13 and distinguished at 0.99, and CAIDI at 87, with threshold at 96 and distinguished at 84. The regulatory/legislative goals for the performance cycle are measured by ratemaking, preservation of the power procurement process, and avoidance of harmful legislation. The goals for the performance cycle are filing the next rate case using a future test year as base, if feasible; managing other regulatory proceedings in support of goals to improve cost recovery, the customer experience, and operations; minimize risks; promote retail competition, energy efficiency, and demand response; and exploring and implementing, where appropriate, new technologies such as AMI or Smart Grid, or processes to enhance the operation of the system or the customer experience. The goal also includes identifying more opportunities to operate cost efficiently and to support the transmission rate case updates; implementing the 2009 procurement process and supporting the IPA to develop policies and plans that reasonably align with ComEd’s goals; and to continue to meet legislative energy efficiency, demand response and renewables requirements; and continuing to avoid legislation that would adversely impact the effective operations or that interferes with the business and support legislation that is helpful to cost recovery, ComEd’s energy efficiency, technology development, retail choice, or environmental goals.

For the performance period of January 1, 2009 through December 31, 2009, ComEd achieved distinguished performance relative to CAIDI (outage duration) and distinguished performance relative to SAIFI (outage frequency). For the same time period, ComEd achieved an above target but below distinguished level of performance relative to 2009 operating return on equity. The Committee considered performance on the financial goal to have been above target. ComEd also achieved a distinguished level of performance relative to its regulatory and legislative goals. Based on their evaluation of this performance, and the desire to cap payouts to achieve a rough parity with long-term incentive payouts of the other Exelon operating companies, the compensation committee recommended and the ComEd board approved payouts to participants for 2009 that represented 100% of each participant’s target opportunity.

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Based on the formula and the exercise of discretion to cap the awards, 2009 ComEd Long-Term Incentive Awards for NEOs were as set forth in the following table. The first third of the award vests upon the award date, with the remaining thirds vesting on the date of the compensation committee’s January meeting in the next two years.


ComEd	Value *		Form of Payment
Clark	$	1,036,000	100% Cash
Trpik		131,556	100% Cash
McDonald		296,186	100% Cash
Pramaggiore		527,342	100% Cash
Hooker		318,000	100% Cash
Donnelly		382,110	100% Cash
Mitchell		714,000	100% Cash

*	Based on 100% of target opportunity.

Performance-Based Restricted Stock Awards; Special Recognition Award

In July 2004, the compensation committee and the Exelon board of directors approved a restricted stock opportunity for Mr. Frank M. Clark and for Ms. Elizabeth Moler of up to 10,000 shares each, with up to 5,000 to be awarded in 2007 and up to 5,000 to be awarded in 2009, based on the qualitative assessment by the Chairman and CEO of their performance with respect to regulatory objectives and the compensation committee’s and the board of directors’ approval. The compensation committee and the board of directors considered these opportunities in July 2009. In recognition of Mr. Clark’s success in obtaining legislative approval of a rider for uncollectible expenses, success in the distribution rate case and the Smart Grid Pilot rider, obtaining approval by the FERC of the transmission formula rate, a successful relationship with the IPA, and ongoing efforts to increase productivity and cost efficiencies and imposing financial discipline, the compensation committee recommended and the Exelon board of directors approved a grant of 5,000 shares. This award was settled in cash instead of stock. In recognition of Ms. Moler’s efforts to defend competitive markets and advocate for climate change legislation, defend the Illinois procurement process, and leading the effort to obtain regulatory approval for the proposed NRG transaction, the compensation committee recommended and the Exelon board of directors approved a grant of 5,000 shares. In November 2009 the compensation committee recommended and the ComEd board approved a cash recognition award of $150,000 for Mr. John T. Hooker in recognition of his accomplishments in leading a team that worked successfully for passage of uncollectible rider legislation and for sponsoring a team that made significant progress on operational efficiency initiatives.

Tax Consequences

Under Section 162(m) of the 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

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excess of $1 million. Annual incentive awards and performance share units payable to NEOs are intended to be qualified performance-based compensation under Section 162(m), and are therefore deductible for Federal income tax purposes. However, because of the element of compensation committee and ComEd board of directors discretion in the 2007-2009 ComEd Long-Term Incentive Program, payments under that program are not eligible for Federal income tax deduction to the extent that, combined with an individual’s base salary, payments exceed $1 million. 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 NEOs’ compensation that is not “qualified performance-based compensation” is in excess of $1 million.

Under Section 4999 of the Internal Revenue Code, there is a steep excise tax if change in control or severance benefits are greater than 2.99 times the five-year average amount of income reported on an individual’s W-2. This provision can have an arbitrary effect, due to the uneven effect of such items as relocation reimbursements and stock option exercises. In addition, the excise tax is imposed if compensation is only $1 greater than the threshold. Accordingly, Exelon had a policy of providing excise tax gross-ups, and avoiding gross-ups by reducing payments to under the threshold if the amount otherwise payable to an executive is not more than 110% of the threshold. In December 2007 the compensation committee reviewed this policy and concluded that it was reasonable. As discussed above, in April 2009 the compensation committee again reviewed this policy and adopted a new policy that no future employment or severance agreement that provides for benefits for NEOs on account of termination will include an excise tax gross-up.

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 2009 Annual Report on Form 10-K and the 2010 Proxy Statement.

February 4, 2010

The Compensation Committee

Rosemarie B. Greco, Chair

John A. Canning, Jr.

M. Walter D’Alessio

William C. Richardson

Stephen D. Steinour

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Summary Compensation Table

The tables below summarize the total compensation paid or earned by each of the NEOs 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, 2009.

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 discretionary bonuses or 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.

Stock awards and option awards show the grant date fair value calculated in accordance with FASB ASC Topic 718.

Stock awards consist primarily of performance share awards pursuant to the terms of the 2006 Long-Term Incentive Plan. The compensation committee established a performance share unit award program 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 a three-year period. The threshold, target and distinguished goals for performance unit share awards are established on the grant date (generally the date of the first compensation committee meeting in the fiscal year). The actual performance against the goals and the number of performance unit share awards are established on the award date (generally the date of the first compensation committee meeting after the completion of the fiscal year). Upon retirement or involuntary termination without 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 stock 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 executive vice presidents and above achieve 200% or more of their applicable stock ownership target, their performance shares will be paid entirely in cash. 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, and in some cases may incorporate performance criteria as well as time-based vesting. 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 in full at one or more pre-determined dates. Amounts of restricted shares held by each NEO, if any, are shown in the footnotes to the Outstanding Equity Table.

All option awards are made pursuant to the terms of the 2006 Long-Term Incentive Plan. 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. 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 a theoretical value of each option determined by the compensation committee using a lattice binomial ratio valuation formula. 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 without cause. Time

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vesting adds a retention element to the stock option program. 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.

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 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. Threshold, target and distinguished (i.e. maximum) achievement levels are established for each goal. Threshold is set at the minimally acceptable level of performance, for a payout of 50% of target. 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, and is capped at 200% of target. Awards are interpolated to the extent performance falls between the threshold, target, and distinguished levels.

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Exelon, Generation and PECO

Summary Compensation Table


Name and Principal Position (A)	Year (B)	Salary ($) (C)		Bonus ($) See Note 21 (D)		Stock Awards ($) See Note 22 (E)		Option Awards ($) See Note 23 (F)		Non-Equity Incentive Plan Compensation ($) See Note 24 (G)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($) See Note 25 (H)		All Other Compen- sation ($) See Note 26 (I)		Total ($) (J)
Rowe⁽¹⁾	2009	$	1,468,077	—		$	6,341,383	$	2,236,650	$	1,573,825	$	173,566	$	416,947	$	12,210,448
	2008		1,474,423	—			6,402,614		2,093,040		1,835,166		830,272		400,192		13,035,707
	2007		1,361,154	—			5,674,614		1,957,500		1,680,249		504,385		418,026		11,595,928

O’Brien⁽²⁾	2009		532,923	—			1,255,539		443,001		395,970		233,772		55,464		2,916,669
	2008		495,538	—			1,280,523		403,920		428,934		105,978		175,687		2,890,580
	2007		450,154	—			785,716		247,950		468,642		99,320		96,339		2,148,121

Hilzinger⁽³⁾	2009		442,769	13,079			609,573		215,007		261,579		85,891		31,725		1,659,623
	2008		408,627	—			992,836		201,960		318,750		57,492		143,916		2,123,581

Barnett⁽⁴⁾	2009		307,996	—			382,121		135,642		153,788		55,038		23,407		1,057,992
	2008		297,308	(16,498	)		394,007		123,012		148,477		35,808		561,590		1,543,704
	2007		283,969	50,000			349,207		110,925		221,075		33,065		80,037		1,128,278

Crane⁽⁵⁾	2009		821,154	—			2,049,674		707,070		680,213		719,399		76,140		5,053,650
	2008		694,230	—			2,748,159		514,080		750,000		642,938		272,727		5,622,134
	2007		558,000	—			2,413,227		456,750		577,536		442,503		158,029		4,606,045

McLean⁽⁶⁾	2009		640,346	—			1,519,384		536,796		437,276		122,086		87,738		3,343,626
	2008		561,538	—			2,281,177		514,080		510,416		95,727		216,544		4,179,482
	2007		482,500	—			1,353,177		456,750		403,276		53,160		96,874		2,845,737

Moler⁽⁷⁾	2009		482,692	—			1,509,839		443,001		282,270		40,181		76,253		2,834,236
	2008		484,615	—			1,280,523		403,920		329,000		333,981		195,611		3,027,650

Pardee⁽⁸⁾	2009		568,615	16,903			1,028,086		363,636		338,052		221,082		33,192		2,569,566
	2008		525,289	44,000			1,788,668		348,840		484,000		213,293		164,619		3,568,709
	2007		426,308	—			785,716		247,950		350,277		110,591		69,591		1,990,433

Cornew⁽⁹⁾	2009		391,308	11,172			609,573		215,007		223,447		99,877		17,175		1,567,559

Adams⁽¹⁰⁾	2009		330,339	16,515			482,200		168,831		165,152		190,121		4,100		1,357,258
	2008		320,000	—			794,269		152,388		175,973		72,722		86,772		1,602,124
	2007		305,008	—			349,207		110,925		222,621		74,219		10,602		1,072,582

Bonney⁽¹¹⁾	2009		284,586	—			336,630		119,769		121,482		337,150		14,840		1,214,457
	2008		273,020	25,000			344,756		110,160		120,951		130,060		74,953		1,078,900

Acevedo⁽¹²⁾	2009		212,208	3,695			119,356				73,899		33,958		10,610		453,726

Galvanoni⁽¹³⁾	2009		220,828	3,934			172,864		62,049		78,689		37,458		11,520		587,342
	2008		214,462	(4,854	)		172,378		62,424		92,213		23,908		66,284		626,815
	2007		199,603	—			386,493		52,200		119,096		20,969		12,707		791,068

375

ComEd

Summary Compensation Table


Name and Principal Position (A)	Year (B)	Salary ($) (C)		Bonus ($) See Note 21 (D)	Stock Awards ($) See Note 22 (E)		Option Awards ($) See Note 23 (F)		Non-Equity Incentive Plan Compensation ($) See Note 24 (G)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($) See Note 25 (H)		All Other Compen- sation ($) See Note 26 (I)		Total ($) (J)
Clark⁽¹⁴⁾	2009	$	564,385	—	$	254,300	$		$	1,461,250	$	180,950	$	85,888	$	2,546,773
	2008		546,692	—						2,049,371		548,986		193,738		3,338,787
	2007		474,231	—		370,500				2,288,853		391,782		146,412		3,671,778

Trpik⁽¹⁵⁾	2009		263,810	6,300		172,864		62,049		257,556		51,563		27,312		841,454

McDonald⁽¹⁶⁾	2009		309,262	—						421,841		1,628,897		944,037		3,304,037
	2008		336,038	—						789,747		304,534		144,201		1,574,520
	2007		310,600	100,000						887,688		225,879		74,566		1,598,733

Pramaggiore⁽¹⁷⁾	2009		391,269	24,900						776,342		89,876		33,774		1,316,161
	2008		348,500	20,295						817,247		49,083		127,421		1,362,546
	2007		290,154	150,000		326,560				347,222		36,593		43,225		1,193,754

Hooker⁽¹⁸⁾	2009		321,923	159,075						499,500		172,435		46,885		1,199,818
	2008		307,692	9,007						657,135		474,488		128,861		1,577,183
	2007		277,231	150,000		326,560				695,830		283,124		65,433		1,798,178

Donnelly⁽¹⁹⁾	2009		326,154	9,625						574,610		134,917		35,392		1,080,698

Mitchell⁽²⁰⁾	2009		471,846	—						998,400		1,517,123		77,702		3,065,071
	2008		477,692	—						1,402,448		571,280		197,955		2,649,375
	2007		437,477	—		408,200				1,592,848		736,464		138,596		3,313,585

Notes to the Summary Compensation Tables

(1)	John W. Rowe, Chairman and CEO, Exelon; Chairman, Generation.

(2)	Denis P. O’Brien, Executive Vice President, Exelon; President and CEO, PECO.

(3)	Matthew F. Hilzinger, Senior Vice President and Chief Financial Officer, Exelon and Generation.

(4)	Phillip S. Barnett, Senior Vice President and Chief Financial Officer, PECO.

(5)	Christopher M. Crane, President and Chief Operating Officer, Exelon and Generation.

(6)	Ian P. McLean, Executive Vice President, Exelon; Chief Executive Officer, Exelon Transmission Company.

(7)	Elizabeth A. Moler, Executive Vice President, Government Affairs and Public Policy, Exelon.

(8)	Charles G. Pardee, Senior Vice President, Exelon; President and Chief Nuclear Officer, Exelon Nuclear (Generation).

(9)	Kenneth W. Cornew, Senior Vice President, Exelon; President, Power Team (Generation).

(10)	Craig L. Adams, Senior Vice President & Chief Operating Officer, PECO.

(11)	Paul R. Bonney, Vice President, Regulatory Affairs and General Counsel, PECO.

(12)	Jorge A. Acevedo, Vice President and Controller, PECO (from June 18, 2009).

(13)	Matthew R. Galvanoni, Vice President, Accounting and Assistant Corporate Controller, Exelon; Chief Accounting Officer, Generation (Principal Accounting Officer).

(14)	Frank M. Clark, Chairman and CEO, ComEd.

(15)	Joseph R. Trpik, Jr., Senior Vice President, Chief Financial Officer and Treasurer, ComEd (from July 6, 2009).

(16)	Robert K. McDonald, Senior Vice President and Chief Financial Officer, ComEd (through May 11, 2009).

(17)	Anne R. Pramaggiore, President and Chief Operating Officer, ComEd.

(18)	John T. Hooker, Senior Vice President, State Legislative and Governmental Affairs, ComEd.

(19)	Terence R. Donnelly, Executive Vice President, Operations, ComEd.

(20)	J. Barry Mitchell, President & COO, ComEd (through May 11, 2009)

(21)	In recognition of their overall performance, certain NEOs received an individual performance multiplier to their annual incentive payments or other special recognition awards in certain years.

(22)

The amounts shown in this column include the aggregate grant date fair value of stock awards granted on January 26, 2009 with respect to the three year performance period ending December 31, 2009. The grant date fair value of the stock award have been computed in accordance with FASB ASC Topic 718 using the assumptions described in Note 16—of the Combined Notes to Consolidated Financial Statements. For the 2009 grants for Messrs. Rowe, O’Brien, Hilzinger, Barnett, Crane, McLean, Ms. Moler, Messrs. Pardee, Cornew, Adams, Bonney, Acevedo, Galvanoni and Trpik, the grant date fair value of their awards assuming that the highest level of performance conditions would be achieved was $7,877,494, $1,559,676, $757,234, $474,684, $2,550,304,

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$1,877,434, $1,559,676, $1,531,426, $757,234, $599,006, $418,174, $143,678, $214,738, and $214,738, respectively. Amounts shown for 2008 and 2007 which were previously reported under prior rules concerning valuation have been restated.

(23)

The amounts shown in this column include the aggregate grant date fair value of stock option awards granted on January 26, 2009. The grant date fair value of the stock options award have been computed in accordance with FASB ASC Topic 718 using the assumptions described in Note 16—of the Combined Notes to Consolidated Financial Statements. Amounts shown for 2008 and 2007 which were previously reported under prior rules concerning valuation have been restated.

(24)

The amounts shown in this column represent payments made pursuant to the Annual Incentive Plan and the ComEd Long-Term Incentive Plan. Both programs are paid with respect to 2009 performance and were awarded on January 25, 2010. The table below details ComEd Employee’s payments applicable to the ComEd Annual Incentive Plan and the ComEd Long-Term Incentive Plan.


Name	Year	Annual Incentive Plan		ComEd Long-Term Incentive Plan		Total
Clark	2009	$	425,250	$	1,036,000	$	1,461,250
	2008		495,371		1,554,000		2,049,371
	2007		475,853		1,813,000		2,288,853
Trpik	2009		126,000		131,556		257,556
McDonald	2009		125,655		296,186		421,841
	2008		195,747		594,000		789,747
	2007		194,688		693,000		887,688
Pramaggiore	2009		249,000		527,342		776,342
	2008		223,247		594,000		817,247
	2007		161,722		185,500		347,222
Hooker	2009		181,500		318,000		499,500
	2008		180,135		477,000		657,135
	2007		139,330		556,500		695,830
Donnelly	2009		192,500		382,110		574,610
Mitchell	2009		284,400		714,000		998,400
	2008		331,448		1,071,000		1,402,448
	2007		343,348		1,249,500		1,592,848

(25)

The amounts shown in the column represent the change in the accumulated pension benefit from December 31, 2008 to December 31, 2009. For certain NEOs the amount may include the value of above market earnings upon their investment in a particular fund within their non-qualified deferred compensation account. For 2009, no NEOs had above market earnings; in 2008, Messrs. Crane, McLean, Pardee and McDonald recognized $48, $160, $30 and $3 of above market earnings respectively. In 2007, these same NEOs recognized $39,150, $1,222, $584 and $1,264 respectively.

(26)	The amounts shown in this column include the items summarized in the following tables:

Exelon, Generation and PECO

All Other Compensation


Name (a)	Perquisites $ See Note 1 (b)		Reimburse- ment for Income Taxes $ See Note 2 (c)		Payments or Accruals for Termination or Change in Control (CIC) $ See Note 3 (d)		Company Contributions to Savings Plans $ See Note 4 (e)		Company Paid Term Life Insurance Premiums $ See Note 5 (f)		Dividends or Earnings not included in Grants $ See Note 6 (g)		Total $ (h)
Rowe	$	195,173	$	8,140	$	—	$	73,404	$	140,230	$	—	$	416,947
O’Brien		1,670		805		—		26,646		26,343		—		55,464
Hilzinger		6,478		—		—		22,138		3,109		—		31,725
Barnett		5,592		—		—		15,400		2,415		—		23,407
Crane		3,581		975		—		40,058		31,526		—		76,140
McLean		—		—		—		32,017		55,721		—		87,738
Moler		4,282		—		—		24,135		47,836		—		76,253
Pardee		—		—		—		28,431		4,761		—		33,192
Cornew		655		518		—		12,250		3,752		—		17,175
Adams		—		—		—		—		4,100		—		4,100
Bonney		470		—		—		12,250		2,120		—		14,840
Acevedo		—		—		—		10,610		—		—		10,610
Galvanoni		—		—		—		11,041		479		—		11,520

377

ComEd

All Other Compensation


Name (a)	Perquisites $ See Note 1 (b)		Reimburse- ment for Income Taxes $ See Note 2 (c)		Payments or Accruals for Temrination or Change in Control (CIC) $ See Note 3 (d)	Company Contributions to Savings Plans $ See Note 4 (e)		Company Paid Term Life Insurance Premiums $ See Note 5 (f)		Dividends or Earnings not included in Grants $ See Note 6 (g)		Total $ (h)
Clark	$	16,573	$	5,604	—	$	28,219	$	35,492	$	—	$	85,888
Trpik		13,209		—	—		13,191		912		—		27,312
McDonald		7,042		—	901,990		12,846		21,818		341		944,037
Pramaggiore		20,837		—	—		9,188		3,749		—		33,774
Hooker		22,200		—	—		16,096		8,589		—		46,885
Donnelly		16,770		—	—		16,308		2,314		—		35,392
Mitchell		2,930		—	—		23,592		51,180		—		77,702

Notes to All Other Compensation Tables

(1)	The amounts shown in this column represent the incremental cost to Exelon to provide certain perquisites to NEOs as summarized in the Perquisites Table below.

(2)	Officers receive a reimbursement to cover applicable taxes on imputed income for business-related spousal travel expenses for those cases where the personal benefit is closely related to the business purpose.

(3)

Represents the expense, if applicable, or the accrual of the expense that Exelon has recorded during 2009 after the announcement of the officer’s retirement or resignation for severance related costs including salary and Annual Incentive Plan (AIP) continuation, outplacement fees, medical benefits, and a prorated portion of his cash retention award.

(4)

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 2009 was generally limited by IRS rules to $16,500. 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 that has the same portfolio of investment options as the 401(k) plan.

(5)

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 2009 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.

(6)	The amount shown for Mr. McDonald represents the payment of retirement deferred compensation units after he ceased employment with ComEd.

Perquisites

Exelon continues to provide executive physicals, parking in downtown Chicago, supplemental long-term disability insurance and executive life insurance for those with existing policies. Exelon provides Mr. Rowe with 60 hours of personal travel per year on the corporate aircraft and car and driver services because of the time commitments his position requires.

378

Exelon, Generation and PECO

Perquisites


Name (a)	Personal and Spouse Travel $ See Note 1 & Note 2 (b)		Automobile Lease and Parking $ See Note 3 (c)		Other Items $ See Note 4 (d)		Total $ (e)
Rowe	$	192,073	$	3,000	$	100	$	195,173
O’Brien		920		—		750		1,670
Hilzinger		—		6,478		—		6,478
Barnett		—		5,592		—		5,592
Crane		—		3,000		581		3,581
Moler		—		4,282		—		4,282
Cornew		555		—		100		655
Bonney		—		—		470		470

ComEd

Perquisites


Name (a)	Personal and Spouse Travel $ See Note 1 & Note 2 (b)		Automobile Lease and Parking $ See Note 3 (c)		Other Items $ See Note 4 (d)		Total $ (e)
Clark	$	7,093	$	9,480	$	—	$	16,573
Trpik		—		13,209		—		13,209
McDonald		—		7,042		—		7,042
Pramaggiore		—		20,837		—		20,837
Hooker		—		22,200		—		22,200
Donnelly		—		16,770		—		16,770
Mitchell		—		2,930		—		2,930

Note to Perquisite Tables

(1)

Mr. Rowe is entitled to up to 60 hours of personal use of corporate aircraft each year. The figure shown in this column includes $183,563, representing the aggregate incremental cost to Exelon for Mr. Rowe’s personal use of corporate aircraft. 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 this amount. 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.

(2)

The company maintains several cars and drivers 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 cars and drivers, 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 drivers worked overtime providing services to each NEO, multiplied by the average overtime rate for drivers plus an additional amount for fuel and maintenance. Personal use was imputed as additional taxable income to Messrs. Rowe, Clark, and O’Brien.

(3)

In 2008, Exelon discontinued the leased vehicle perquisite for all officers effective at the lease expiration date. Certain leases expired in early 2009. Exelon continued to provide insurance, maintenance, applicable taxes and provided a company-paid credit card for fuel purchases while the leases were in effect. Where required, such as in downtown Chicago, Exelon provides company-paid parking for NEOs.

(4)	Executive officers may use company-provided vendors for comprehensive physical examinations and related follow-up testing. Executives also receive certain gifts during the year in recognition of their services that are imputed to the officer as additional taxable income.

379

Exelon, Generation and PECO

Grants of Plan Based Awards


		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) (#) (i)	All Other Options Awards: Number of Securities Under- lying Options (#) (j)	Exercise or base Price of Option Awards. ($) (k)	Grant Date Fair Value of Stock and Option Awards (See Note 4) ($) (l)
Name (a)	Grant Date (b)	Threshold ($) (c)		Target ($) (d)		Maximum ($) (e)		Thres- hold (#) (f)	Target (#) (g)	Maxi- mum (#) (h)
Rowe	26 Jan. 2009	$	811,250	$	1,622,500	$	3,245,000
	26 Jan. 2009							34,850	69,700	139,400				6,341,383
	26 Jan. 2009											155,000	56.51	2,236,650
O’Brien	26 Jan. 2009		201,000		402,000		804,000
	26 Jan.2009							6,900	13,800	27,600				1,255,539
	26 Jan.2009											30,700	56.51	443,001
Hilzinger	26 Jan.2009		133,800		267,600		535,200
	26 Jan.2009							3,350	6,700	13,400				609,573
	26 Jan.2009											14,900	56.51	215,007
Barnett	26 Jan.2009		77,475		154,950		309,900
	26 Jan.2009							2,100	4,200	8,400				382,121
	26 Jan.2009											9,400	56.51	135,642
Crane	26 Jan.2009		330,000		660,000		1,320,000
	3 Aug.2009		20,625		41,250		82,500
	26 Jan.2009							11,000	22,000	44,000				2,001,584
	3 Aug.2009							311	621	1,242				48,089
	26 Jan.2009											49,000	56.51	707,070
McLean	26 Jan.2009		225,400		450,800		901,600
	26 Jan.2009							8,350	16,700	33,400				1,519,384
	26 Jan.2009											37,200	56.51	536,796
Moler	26 Jan.2009		145,500		291,000		582,000
	26 Jan.2009							6,900	13,800	27,600				1,255,539
	26 Jan.2009											30,700	56.51	443,001
	1 Aug.2009										5,000			254,300
Pardee	26 Jan.2009		171,600		343,200		686,400
	26 Jan.2009							5,650	11,300	22,600				1,028,086
	26 Jan.2009											25,200	56.51	363,636
Cornew	26 Jan.2009		128,050		256,100		512,200
	26 Jan.2009							3,350	6,700	13,400				609,573
	26 Jan.2009											14,900	56.51	215,007
Adams	26 Jan.2009		83,200		166,400		332,800
	26 Jan.2009							2,650	5,300	10,600				482,200
	26 Jan.2009											11,700	56.51	168,831
Bonney	26 Jan.2009		57,186		114,371		228,742
	7 Dec. 2009		4,014		8,029		16,058
	26 Jan.2009							1,850	3,700	7,400				336,630
	26 Jan.2009											8,300	56.51	119,769
Acevedo	26 Jan.2009		31,789		63,578		127,156
	22 Jun.2009		6,011		12,022		24,044
	22 Jun.2009							503	1,005	2,010				74,148
	26 Jan.2009										800			45,208
Galvanoni	26 Jan.2009		37,856		75,712		151,424
	3 Aug. 2009		2,394		4,788		9,576
	26 Jan.2009							950	1,900	3,800				172,864
	26 Jan.2009											4,300	56.51	62,049

380

ComEd

Grants of Plan Based Awards


Name (a)	Grant Date (b)											All other Stock Awards: Number of Shares or Units (See Note 3) (#) (i)	All Other Options Awards: Number of Securities Under- lying Options (#) (j)	Exercise or base Price of Option Awards. ($) (k)	Grant Date Fair Value of Stock and Option Awards (See Note 4) ($) (l)
			Estimated Future Payouts Under Non-Equity Incentive Plan Awards (See Note 1)						Estimated Future Payouts Under Equity Incentive Plan Awards (See Note 2)
			Thres- hold ($) (c)		Target ($) (d)		Maxi- mum ($) (e)		Thres- hold (#) (f)	Target (#) (g)	Maxi- mum (#) (h)
Clark	26 Jan.2009	CE LTI	$	518,000	$	1,036,000	$	2,072,000
	26 Jan.2009	AIP		212,625		425,250		850,500
	1 Aug.2009											5,000			254,300

Trpik ⁽¹⁾	3 Aug.2009	CE LTI		65,778		131,556		263,112
	26 Jan.2009	AIP		44,547		89,093		178,186
	3 Aug. 2009	AIP		18,454		36,907		73,814
	26 Jan.2009								950	1,900	3,800				172,864
	26 Jan.2009												4,300	56.51	62,049

McDonald	26 Jan.2009	CE LTI		198,000		396,000		792,000
	26 Jan.2009	AIP		84,000		168,000		336,000

Pramaggiore	26 Jan.2009	CE LTI		198,000		396,000		792,000
	11 May 2009	CE LTI		65,671		131,342		262,684
	26 Jan.2009	AIP		88,300		176,600		353,200
	11 May 2009	AIP		36,200		72,400		144,800

Hooker	26 Jan.2009	CE LTI		159,000		318,000		636,000
	26 Jan.2009	AIP		78,000		156,000		312,000
	11 May 2009	AIP		12,750		25,500		51,000

Donnelly	26 Jan.2009	CE LTI		178,500		357,000		714,000
	11 May 2009	CE LTI		12,555		25,110		50,220
	26 Jan.2009	AIP		71,500		143,000		286,000
	11 May 2009	AIP		24,750		49,500		99,000

Mitchell	26 Jan.2009	CE LTI		357,000		714,000		1,428,000
	26 Jan.2009	AIP		142,200		284,400		568,800

Notes to Grants of Plan Based Awards Tables

(1)

All NEOs have annual incentive plan target opportunities based on a fixed percentage of their base salary. ComEd NEOs have a long-term incentive plan target based on a cash target (for the ComEd NEOs, the rows labeled “CE LTI” are for the long-term incentive, and the rows labeled “AIP” are for the annual incentive). Under the terms of both incentive plans, threshold performance earns 50% of the respective target while the maximum payout is capped at 200% of target. For additional information about the terms of these programs, see Compensation Discussion and Analysis above.

(2)

Non-ComEd NEOs have a long-term performance share target opportunity that is a fixed number of performance shares commensurate with the officer’s position. For additional information about the terms of these programs, see Compensation Discussion and Analysis and the narrative preceding the Summary Compensation Table above.

(3)

This column shows additional restricted share awards made during the year. For additional information about the awards to Ms. Moler and Mr. Clark, see Compensation Discussion and Analysis—Performance-Based Restricted Stock Awards; Special Recognition Award. For Mr. Acevedo, represents a key manager restricted stock award granted before he became an officer. The vesting dates of the awards are provide in the footnote 2 to the Outstanding Equity Table below.

(4)

This column shows the grant date fair value, calculated in accordance with FASB ASC Topic 718, of the performance share awards, stock options, and restricted stock granted to each NEO during 2009. Fair value of performance share awards granted on January 26, 2009 is based on an estimated payout of 161% of target. Fair value of performance share awards granted on June 22, 2009 and August 3, 2009 is based on an estimated payout of 151% of target.

381

Exelon, Generation and PECO

Outstanding Equity


	Options (See Note 1)						Stock (See Note 2)
Name (a)	Number of Securities Underlying Unexercised Options That Are Exercisable (#) (b)	Number of Securities Underlying Unexercised Options That Are Not Exercisable (#) (c)	Option Exercise or Base Price ($) (d)		Option Grant Date (e)	Option Expiration Date (f)	Number of Shares or Units of Stock That Have Not Yet Vested (#) (g)	Market Value of Share or Units of Stock That Have Not Yet Vested Based on 12/31 Closing Price $48.87 ($) (h)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Yet Vested (#) (i)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Yet Vested ($) (j)
Rowe	—	155,000	$	56.51	26 Jan. 2009	25 Jan. 2019	115,429	$	5,641,015	69,700	$	3,406,239
	28,500	85,500		73.29	28 Jan. 2008	27 Jan. 2018
	75,000	75,000		59.96	22 Jan. 2007	21 Jan. 2017
	229,000	—		42.85	24 Jan. 2005	23 Jan. 2015

O’Brien	—	30,700		56.51	26 Jan. 2009	25 Jan. 2019	20,436		998,707	13,800		674,406
	5,500	16,500		73.29	28 Jan. 2008	27 Jan. 2018
	9,500	9,500		59.96	22 Jan. 2007	21 Jan. 2017
	15,000	5,000		58.55	23 Jan. 2006	22 Jan. 2016
	29,000	—		42.85	24 Jan. 2005	23 Jan. 2015
	30,000	—		32.54	26 Jan. 2004	25 Jan. 2014
	30,000	—		24.81	27 Jan. 2003	26 Jan. 2013
	9,000	—		21.91	01 Aug. 2000	31 Jul. 2010
	8,000	—		18.66	29 Feb. 2000	27 Feb. 2010

Hilzinger	—	14,900		56.51	26 Jan. 2009	25 Jan. 2019	15,271		746,294	6,700		327,429
	2,750	8,250		73.29	28 Jan. 2008	27 Jan. 2018
	5,250	5,250		59.96	22 Jan. 2007	21 Jan. 2017
	7,875	2,625		58.55	23 Jan. 2006	22 Jan. 2016
	14,000	—		42.85	24 Jan. 2005	23 Jan. 2015
	4,500	—		32.54	26 Jan. 2004	25 Jan. 2014

Barnett	—	9,400		56.51	26 Jan. 2009	25 Jan. 2019	11,103		542,604	4,200		205,254
	1,675	5,025		73.29	28 Jan. 2008	27 Jan. 2018
	4,250	4,250		59.96	22 Jan. 2007	21 Jan. 2017
	6,375	2,125		58.55	23 Jan. 2006	22 Jan. 2016
	9,675	—		42.85	24 Jan. 2005	23 Jan. 2015
	3,500	—		32.54	26 Jan. 2004	25 Jan. 2014

Crane	—	49,000		56.51	26 Jan. 2009	25 Jan. 2019	58,514		2,859,579	22,621		1,105,488
	7,000	21,000		73.29	28 Jan. 2008	27 Jan. 2018
	17,500	17,500		59.96	22 Jan. 2007	21 Jan. 2017
	15,000	7,500		58.55	23 Jan. 2006	22 Jan. 2016
	18,000	—		42.85	24 Jan. 2005	23 Jan. 2015
	13,500	—		32.54	26 Jan. 2004	25 Jan. 2014

McLean	—	37,200		56.51	26 Jan. 2009	25 Jan. 2019	37,526		1,833,896	16,700		816,129
	7,000	21,000		73.29	28 Jan. 2008	27 Jan. 2018
	17,500	17,500		59.96	22 Jan. 2007	21 Jan. 2017
	26,250	8,750		58.55	23 Jan. 2006	22 Jan. 2016
	56,000	—		42.85	24 Jan. 2005	23 Jan. 2015
	80,000	—		32.54	26 Jan. 2004	25 Jan. 2014
	72,000	—		24.81	27 Jan. 2003	26 Jan. 2013
	9,288	—		24.84	25 Feb. 2002	24 Feb. 2012
	90,000	—		23.46	28 Jan. 2002	27 Jan. 2012
	33,600	—		29.75	20 Oct. 2000	19 Oct. 2010

382


	Options (See Note 1)					Stock (See Note 2)
Name (a)	Number of Securities Underlying Unexercised Options That Are Exercisable (#) (b)	Number of Securities Underlying Unexercised Options That Are Not Exercisable (#) (c)	Option Exercise or Base Price ($) (d)	Option Grant Date (e)	Option Expiration Date (f)	Number of Shares or Units of Stock That Have Not Yet Vested (#) (g)	Market Value of Share or Units of Stock That Have Not Yet Vested Based on 12/31 Closing Price $48.87 ($) (h)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Yet Vested (#) (i)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Yet Vested ($) (j)

Moler	—	30,700	56.51	26 Jan. 2009	25 Jan. 2019	23,086	1,128,213	13,800	674,406
	5,500	16,500	73.29	28 Jan. 2008	27 Jan. 2018
	14,000	14,000	59.96	22 Jan. 2007	21 Jan. 2017
	22,500	7,500	58.55	23 Jan. 2006	22 Jan. 2016
	36,000	—	42.85	24 Jan. 2005	23 Jan. 2015

Pardee	—	25,200	56.51	26 Jan. 2009	25 Jan. 2019	35,653	1,742,362	11,300	552,231
	4,750	14,250	73.29	28 Jan. 2008	27 Jan. 2018
	9,500	9,500	59.96	22 Jan. 2007	21 Jan. 2017
	8,500	4,250	58.55	23 Jan. 2006	22 Jan. 2016
	14,500	—	42.85	24 Jan. 2005	23 Jan. 2015
	10,000	—	32.54	26 Jan. 2004	25 Jan. 2014

Cornew	—	14,900	56.51	26 Jan. 2009	25 Jan. 2019	18,609	909,422	6,700	327,429
	2,750	8,250	73.29	28 Jan. 2008	27 Jan. 2018
	4,250	4,250	59.96	22 Jan. 2007	21 Jan. 2017
	4,250	2,125	58.55	23 Jan. 2006	22 Jan. 2016
	5,550	—	42.85	24 Jan. 2005	23 Jan. 2015
	4,051	—	32.54	26 Jan. 2004	25 Jan. 2014

Adams	—	11,700	56.51	26 Jan. 2009	25 Jan. 2019	12,217	597,045	5,300	259,011
	2,075	6,225	73.29	28 Jan. 2008	27 Jan. 2018
	4,250	4,250	59.96	22 Jan. 2007	21 Jan. 2017
	6,375	2,125	58.55	23 Jan. 2006	22 Jan. 2016
	7,000	—	42.85	24 Jan. 2005	23 Jan. 2015
	4,500	—	32.54	26 Jan. 2004	25 Jan. 2014

Bonney	—	8,300	56.51	26 Jan. 2009	25 Jan. 2019	6,216	303,776	3,700	180,819
	1,500	4,500	73.29	28 Jan. 2008	27 Jan. 2018
	3,850	3,850	59.96	22 Jan. 2007	21 Jan. 2017
	5,850	1,950	58.55	23 Jan. 2006	22 Jan. 2016
	6,900	—	42.85	24 Jan. 2005	23 Jan. 2015
	4,500	—	32.54	26 Jan. 2004	25 Jan. 2014

Acevedo	5,025	1,675	58.55	23 Jan. 2006	22 Jan. 2016	1,522	74,380	1,005	49,114
(Note 3)	4,100	—	42.85	24 Jan. 2005	23 Jan. 2015
	2,000	—	32.54	26 Jan. 2004	25 Jan. 2014

Galvanoni	—	4,300	56.51	26 Jan. 2009	25 Jan. 2019	6,141	300,111	1,900	92,853
	850	2,550	73.29	28 Jan. 2008	27 Jan. 2018
	2,000	2,000	59.96	22 Jan. 2007	21 Jan. 2017
	5,025	1,675	58.55	23 Jan. 2006	22 Jan. 2016
	4,100	—	42.85	24 Jan. 2005	23 Jan. 2015
	1,500	—	32.54	26 Jan. 2004	25 Jan. 2014

383

ComEd

Outstanding Equity


	Options (See Note 1)						Stock (See Note 2)
Name (a)	Number of Securities Underlying Unexercised Options That Are Exercisable (#) (b)	Number of Securities Underlying Unexercised Options That Are Not Exercisable (#) (c)	Option Exercise or Base Price ($) (d)		Option Grant Date (e)	Option Expiration Date (f)	Number of Shares or Units of Stock That Have Not Yet Vested (#) (g)	Market Value of Share or Units of Stock That Have Not Yet Vested Based on 12/31 Closing Price $48.87 ($) (h)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Yet Vested (#) (i)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Yet Vested ($) (j)
Clark	22,500	7,500	$	58.55	23 Jan. 2006	22 Jan. 2016	—	$	—	—	—
	36,000	—		42.85	24 Jan. 2005	23 Jan. 2015

Trpik	—	4,300		56.51	26 Jan. 2009	25 Jan. 2019	6,141		300,111	1,114	54,441
(Note 4)	850	2,550		73.29	28 Jan. 2008	27 Jan. 2018
	2,000	2,000		59.96	22 Jan. 2007	21 Jan. 2017
	2,038	1,025		58.55	23 Jan. 2006	22 Jan. 2016
	3,262	—		42.85	24 Jan. 2005	23 Jan. 2015
	1,625	—		32.54	26 Jan. 2004	25 Jan. 2014

McDonald	10,500	—		58.55	23 Jan. 2006	01 Oct. 2014	—		—	—	—
(Note 5)	10,500	—		42.85	24 Jan. 2005	01 Oct. 2014
	9,000	—		32.54	26 Jan. 2004	25 Jan. 2014
	4,250	—		24.81	27 Jan. 2003	26 Jan. 2013

Pramaggiore	3,975	1,325		58.55	23 Jan. 2006	22 Jan. 2016	9,000		439,830	—	—
	10,150	—		42.85	24 Jan. 2005	23 Jan. 2015
	11,400	—		32.54	26 Jan. 2004	25 Jan. 2014

Hooker	2,125	2,125		58.55	23 Jan. 2006	22 Jan. 2016	—		—	—	—
	3,250	—		42.85	24 Jan. 2005	23 Jan. 2015

Donnelly	4,250	4,250		59.96	22 Jan. 2007	21 Jan. 2017	10,650		520,466	—	—
	4,875	1,625		58.55	23 Jan. 2006	22 Jan. 2016
	10,000	—		42.85	24 Jan. 2005	23 Jan. 2015
	13,000	—		32.54	26 Jan. 2004	25 Jan. 2014
	13,800	—		24.81	27 Jan. 2003	26 Jan. 2013
	10,000	—		23.46	28 Jan. 2002	27 Jan. 2012
	7,000	—		29.75	20 Oct. 2000	19 Oct. 2010

Mitchell	15,000	5,000		58.55	23 Jan. 2006	01 Jan. 2015	—		—	—	—
(Note 5)	5,250	—		42.85	24 Jan. 2005	01 Jan. 2015

Notes to Outstanding Equity Tables

(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, 2008 and December 31, 2007, and any unvested restricted stock unit awards as shown in the following table. The amount of shares shown in column (i) represents the target number of performance shares available to each NEO for the performance period ending December 31, 2009. Shares are valued at $48.87, the closing price on December 31, 2009.

(3)	Mr. Acevedo’s performance share award was prorated from the date he became Vice President and Controller of PECO.

384

(4)	Mr. Trpik’s performance share award was prorated through the date he became Senior Vice President, CFO and Treasurer of ComEd and became eligible for the ComEd Long Term Incentive Plan.

(5)	For Mr. McDonald and Mr. Mitchell, their 2005 and 2006 stock option grants will expire on the fifth anniversary of their respective termination dates.

Unvested Restricted Stock or Restricted Stock Units


Name	Grant Date	Number of Restricted Shares	Vesting Dates
Hilzinger	01 Aug. 2008	5,000	01 Aug. 2013
Barnett	01 Apr. 2005	4,000	01 Apr. 2010
Crane	03 Sep. 2007	15,000	03 Sep. 2011
	01 Aug. 2008	15,000	01 Aug. 2013
McLean	01 Aug. 2008	5,000	01 Aug. 2011
	01 Aug. 2008	5,000	01 Aug. 2013
Pardee	01 Jan. 2005	8,000	01 Jan. 2010
	01 Aug. 2008	10,000	01 Aug. 2013
Cornew	01 Apr. 2005	4,000	01 Apr. 2010
	01 Aug. 2008	5,000	01 Aug. 2013
Adams	01 Aug. 2008	4,000	01 Aug. 2013
Acevedo	22 Jan. 2007	257	25 Jan. 2010
	28 Jan. 2008	430	25 Jan. 2010, 24 Jan. 2011
	26 Jan. 2009	835	25 Jan. 2010, 24 Jan. 2011, 23 Jan. 2012
Galvanoni	01 May 2007	3,000	01 May 2011

Name	Grant Date	Number of Restricted Shares	Vesting Dates
Trpik	01 May 2007	3,000	01 May 2011
Pramaggiore	28 Nov. 2005	5,000	28 Nov. 2010
	03 Sep. 2007	4,000	03 Sep. 2012
Donnelly	01 Apr. 2005	4,000	01 Apr. 2010
	03 Sep. 2007	4,000	03 Sep. 2012

385

Exelon, Generation and PECO

Option Exercises and Stock Vested


	Option Awards (See Note 1)			Stock Awards (See Note 2)
Name (a)	Number of Shares Acquired on Exercise (b) (#)	Value Realized on Exercise (c) ($)		Number of Shares Acquired on Vesting (d) (#)	Value Realized on Vesting (e) ($)
Rowe	—	$	—	120,757	$	6,823,976
O’Brien (Note 3)	—		—	23,494		1,316,173
Hilzinger (Note 4)	—		—	17,756		958,174
Barnett	—		—	7,271		410,897
Crane (Note 5)	—		—	47,025		2,577,971
McLean	22,400		427,056	28,826		1,628,960
Moler (Note 6)	—		—	33,631		1,844,015
Pardee	—		—	16,510		933,001
Cornew	—		—	8,471		478,714
Adams	—		—	7,805		441,036
Bonney	—		—	6,492		366,890
Acevedo (Note 7)	—		—	3,452		161,379
Galvanoni	—		—	2,076		117,288

ComEd

Option Exercises and Stock Vested


	Option Awards (See Note 1)			Stock Awards (See Note 2)
Name (a)	Number of Shares Acquired on Exercise (b) (#)	Value Realized on Exercise (c) ($)		Number of Shares Acquired on Vesting (d) (#)	Value Realized on Vesting (e) ($)
Clark (Note 8)	—	$	—	18,449	$	986,027
Trpik	—		—	3,310		187,065
McDonald	—		—	3,249		183,626
Pramaggiore	—		—	1,690		95,485
Hooker	—		—	2,600		146,901
Donnelly	2,000		40,420	4,488		253,617
Mitchell (Note 9)	—		—	10,849		568,826

Notes to Option Exercises and Stock Vested Table

(1)

Mr. McLean exercised all options shown above pursuant to a Rule 10b5-1 trading plan that was entered into when he was unaware of any material information regarding Exelon that had not been publicly disclosed. At that time the formula for the dates, number of options, and sale price was set at the time the trading plans were established.

(2)

Share amounts are generally composed of performance shares that vested on January 26, 2009, which included 1/3 of the grant made with respect to the three-year performance period ending December 31, 2008; 1/3 of the grant made with respect to the three-year performance period ending December 31, 2007, and 1/3 of the grant made with respect to the three-year performance period ending December 31, 2006. Shares were valued at $55.61 upon vesting.

(3)	For Mr. O’Brien, the shares received upon vesting includes 5,000 restricted shares that vested on February 1, 2009 and were valued at $54.22.

(4)	For Mr. Hilzinger, the shares received upon vesting includes 8,000 restricted shares that vested on August 1, 2009 and were valued at $50.86.

386

(5)	For Mr. Crane, the shares received upon vesting includes 10,000 restricted shares that vested on February 1, 2009 and were valued at $54.22, and 10,000 restricted shares that vested on August 1, 2009 and were valued at $50.86.

(6)	For Ms. Moler, the shares received upon vesting includes 10,000 restricted shares that vested on August 1, 2009 and were valued at $50.86.

(7)	For Mr. Acevedo, the shares received upon vesting includes 452 shares from the Key Manager Restricted Stock Unit Program that vested on January 25, 2009 that were valued at $56.51 and 3,000 restricted shares that vested on April 1, 2009 that were valued at $45.28.

(8)	For Mr. Clark, the shares received upon vesting includes 10,000 restricted shares that vested on August 1, 2009 and were valued at $50.86.

(9)	For Mr. Mitchell, the shares received upon vesting includes 5,000 restricted shares that vested on November 27, 2009 and were valued at $47.66.

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. The Exelon Corporation Retirement Program includes the Service Annuity System (SAS), the legacy ComEd pension plan, and the Service Annuity Plan (SAP), the legacy PECO pension plan. 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 balance plan. Each of these plans is intended to be tax-qualified under Section 401(a) of the Internal Revenue Code. An employee can participate in only one of the qualified pension plans.

For NEOs participating in the SAS, the annuity benefit payable at normal retirement age is equal to the sum of 1.25% of the participant’s earnings as of December 25, 1994, reduced by a portion of the participant’s Social Security benefit as of that date, plus 1.6% of the participant’s highest average annual pay, multiplied by the participant’s years of credited service (up to a maximum of 40 years). For NEOs participating in the SAP, the annuity benefit payable at normal retirement age is equal to the greater of the amount determined under the Career Pay Formula, which is 2% of each year’s pensionable pay, and the amount determined under the Final Average Pay Formula, which is the sum of (a) 5% of average earnings, plus 1.2% of average earnings for each year of pension service (up to a maximum of 40 years), and (b) 0.35% of average earnings in excess of covered compensation for each year of pension service (up to a maximum of 40 years). Pension-eligible compensation for the SAS and the SAP’s Final Average Pay Formula includes base pay and annual incentive awards. Pension eligible compensation in the SAP’s Career Pay Formula includes base pay, incentive awards and other regular remuneration. Benefits under the SAS and SAP are vested after five years of service.

The “normal retirement age” under both the SAS and the SAP is 65. Each of these plans also offers an early retirement benefit prior to age 65, which is payable if a participant retires after attainment of age 50 and completion of ten years of service. The annual pension payable under each plan is determined as of the early retirement date, reduced by 2% for each year of payment before age 60 to age 58, then 3% for each year before age 58 to age 50. In addition, under the SAS, the early retirement benefit is supplemented by a temporary payment equal to 80% of the participant’s estimated monthly Social Security benefit, offset by the aggregate annual amount of the temporary supplemental payment multiplied by a plan factor, determined on a partially subsidized actuarial basis. The supplemental benefit is partially offset by a reduction in the regular annuity benefit.

Under the cash balance pension plan, a notional account is established for each participant, and the account balance grows as a result of annual benefit credits and annual investment credits. (Employees who participated in the SAS or the SAP prior to January 1, 2001 and elected to transfer to

387

the cash balance plan also have a frozen transferred benefit from the former plan, and received a “transition” credit based on their age, service and compensation at the time of transfer.) Beginning January 1, 2008, the annual benefit credit under the plan is 7.00% of base pay and annual incentive award (subject to applicable Internal Revenue Code limit). For the portion of the account balance accrued beginning January 1, 2008, the annual investment credit is the third segment rate of interest on long-term investment grade corporate bonds, as provided for in Internal Revenue Code Section 430(h)(2)(C)(iii). The Segment Rate will be determined as of November of the year for which the cash balance account receives the investment credit. For the portion of the benefit accrued before January 1, 2008, pending Internal Revenue Service guidance, 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 non-forfeitable after completion of at least three years of service, and are payable in an annuity or a lump sum at any time 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 $245,000 the individual annual compensation that may be taken into account under the tax-qualified retirement plan. As permitted by Employee Retirement Income Security Act, Exelon sponsors two supplemental executive retirement plans (or “SERPs”) that allow the payment to a select group of management or highly-compensated individuals out of its general assets of any benefits calculated under provisions of the applicable qualified pension plan which may be above these limits. The SERPs offers a lump sum as an optional form of payment, which includes the value of the marital annuity, death benefits and other early retirement subsidies as a designated interest rate. The interest rate applicable for distributions to participants in the SAS in 2009 is 2.87% and for participants in the SAP in 2009 is 4%. For participants in the cash balance pension plan, the lump sum is the value of the non-qualified account balance. The value of the lump sum amounts do not include the value of any pension benefits covered under the qualified pension plans, and the methods and assumptions used to determine the non-qualified lump sum amount are different than the assumptions used to generate the present values shown in the tables of benefits to be received upon retirement, termination due to death or disability, involuntary separation not related to a change in control, or upon a qualifying termination following a change in control which appear later in this document.

Under the terms of the SERPs, participants are provided the amount of benefits they would have received under the SAS, SAP or cash balance plan, as applicable, but for the application of the Internal Revenue Code limits. In addition, certain executives previously received grants of additional under a SERP. In particular, 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. Ms. Moler received as part of her employment offer an additional five years of credited service after the completion of five years of service, which occurred in 2005. Pursuant to his employment agreement first entered into when he joined the Company in 1998, Mr. Rowe is entitled to receive a SERP benefit that, when added to SAS benefit, will be determined as though 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. A portion of Mr. Rowe’s benefit may be forfeited upon a termination for “cause” (see below under Potential Payments upon Termination or Change in Control—Employment Agreement with Mr. Rowe).

As of January 1, 2004, Exelon does not grant additional years of credited service to executives under the SERP 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

388

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.

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. The assumptions used in estimating the present values include the following: for Service Annuity System participants, pension benefits are assumed to begin at each participant’s earliest unreduced retirement age; and for cash balance plan participants, pension benefits are assumed to begin at the earliest unreduced age. The applicable discount rates are 6.09% as of December 31, 2008 and 5.83% as of December 31, 2009. The lump sum rate amounts are determined using the rate of 6% for SAS participants and 4.0% for SAP participants, both at the assumed retirement age, and the account balance for cash balance pension plan participants. The applicable mortality table as of December 31, 2008 is the IRS-required mortality table for 2009 funding valuation. The applicable table as of December 31, 2009 is the IRS required mortality table for 2010 funding valuation.

Exelon, Generation and PECO


Name (a)	Plan Name (b)	Number of Years Credited Service (#) (c)	Present Value of Accumulated Benefit ($) (d)	Payments During Last Fiscal Year ($) (e)
Rowe (Note 1)	SAS	11.80	480,997	—
	SERP	31.80	16,560,774	—
O’Brien	Cash Balance	27.51	725,527	—
	SERP	27.51	643,441	—
Hilzinger	Cash Balance	7.72	138,859	—
	SERP	7.72	199,688	—
Barnett	Cash Balance	6.68	116,012	—
	SERP	6.68	105,170	—
Crane	SAS	11.26	327,259	—
	SERP	21.26	2,789,462	—
McLean	Cash Balance	7.00	117,737	—
	SERP	7.00	350,614	—
Moler	SAS	9.99	444,643	—
	SERP	14.99	1,793,259	—
Pardee	SAS	9.84	253,124	—
	SERP	9.84	657,389	—
Cornew	Cash Balance	15.59	291,534	—
	SERP	15.59	201,397	—
Adams	Cash Balance	20.38	713,885	—
	SERP	20.38	499,023	—
Bonney	SAP	20.00	674,456	—
	SERP	20.00	565,690	—
Acevedo	Cash Balance	7.17	119,103	—
	SERP	7.17	15,694	—
Galvanoni	Cash Balance	7.16	120,845	—
	SERP	7.16	26,849	—

389

ComEd


Name (a)	Plan Name (b)	Number of Years Credited Service (#) (c)	Present Value of Accumulated Benefit ($) (d)	Payments During Last Fiscal Year ($) (e)
Clark	SAS	40.00	1,761,626	—
	SERP	40.00	4,846,533	—
Trpik	Cash Balance	8.60	156,392	—
	SERP	8.60	65,673	—
McDonald	SAS	31.02	1,139,957	—
	SERP	31.02	2,595,304	—
Pramaggiore	Cash Balance	11.93	274,611	—
	SERP	11.93	112,729	—
Hooker	SAS	40.00	1,894,394	—
	SERP	40.00	1,648,205	—
Donnelly	Cash Balance	26.53	621,708	—
	SERP	26.53	168,377	—
Mitchell	SAP	38.50	1,902,792	—
	SERP	38.50	4,764,598	—

(1)

Based on discount rates prescribed by the SEC executive compensation disclosure rules, the present value of Mr. Rowe’s SERP benefit is $16,560,774. Based on lump sum plan rates for immediate distributions, the comparable lump sum amount applicable for service through December 31, 2009 is $24,164,180. Note that, in any event, payments made upon termination may be delayed for six months in accordance with U.S. Treasury Department guidance.

Deferred Compensation Programs

Exelon offers deferred compensation plans to permit the deferral of certain cash compensation to facilitate tax and retirement planning and satisfaction of stock ownership requirements for executives and 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 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 (the “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 make matching contributions in a relatively tax-efficient manner. 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 is a non-qualified plan that permitted executives to defer performance share units prior to 2007.

In response to declining plan enrollment and the administrative complexity of compliance with Section 409A of the Code, the compensation committee approved amendments to the Deferred Compensation and Stock Deferral Plans at its December 4, 2006 meeting. The amendments cease future compensation deferrals for the Stock Deferral Plan and Deferred Compensation Plan other than the excess Employee Savings Plan contribution deferrals.

390

The following tables show the amounts that NEOs have accumulated under both the Deferred Compensation Plan and the Stock Deferral Plan. Both plans were closed to new deferrals of base pay, annual incentive payments or performance shares awards in 2007, and participants were granted a one-time election to receive a distribution of their accumulated balance in each plan during 2007. The plans will continue in effect for those officers who did not elect to receive the one-time distribution, and their balances will continue to accrue dividends or other earnings until payout upon termination. 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. Share balances in the Stock Deferral Plan 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 or installments upon termination of employment.

The Deferred Compensation Plan continues in effect, without change, for those officers who participate in the 401(k) savings plan and who reach their statutory contribution limit during the year. After this limit is reached, their elected payroll contributions and company matching contribution will be 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. Deferred amounts generally represent unfunded unsecured obligations of the company.

Exelon, Generation and PECO

Nonqualified Deferred Compensation


Name (a)	Executive Contributions in 2009 (b) Note (1)		Registrant Contributions in 2009 (c) Note (2)		Aggregate Earnings in 2009 (d) Note (3)		Aggregate Withdrawals/ Distributions (e)	Aggregate Balance at 12/31/09 (f) Note (4)
Rowe	$	61,154	$	61,154	31,801		—	$	337,231
O’Brien		14,396		14,396	165,063		—		1,330,197
Hilzinger		9,888		9,888	3,581		—		47,254
Barnett		29,699		9,535	12,798		—		111,688
Crane		65,615		32,298	2,071		—		236,525
McLean		19,767		19,767	(22,741	)	—		421,222
Moler		31,769		15,048	15,366		—		132,920
Pardee		40,362		19,462	1,085		—		153,708
Galvanoni		3,374		1,769	1,082		—		12,276

Nonqualified Deferred Compensation

ComEd


Name (a)	Executive Contributions in 2009 (b) Note (1)		Registrant Contributions in 2009 (c) Note (2)		Aggregate Earnings in 2009 (d) Note (3)		Aggregate Withdrawals/ Distributions (e)	Aggregate Balance at 12/31/09 (f) Note (4)
Clark	$	39,938	$	19,221	(6,463	)	—	$	138,748
Trpik		1,129		941	233		—		4,960
McDonald		715		596	1,185		—		21,601
Hooker		15,692		7,615	(11,736	)	—		177,123
Donnelly		29,162		10,096	(1,219	)	—		122,109
Mitchell		30,685		14,585	12,307		—		131,335

(1)	The full amount shown for executive contributions are included in the base salary figures for each NEO shown above in the Summary Compensation Table.

391

(2)	The full amount shown under registrant contributions are included in the company contributions to savings plans for each NEO shown above in the All Other Compensation Table.

(3)

The amount shown under aggregate earnings reflects the NEOs gain or loss based upon the individual allocation of their notional account balance into the basket of mutual fund benchmarks. These gains or losses do not represent current income to the NEO and have not been included in any of the compensation tables shown above.

(4)

For all NEOs the aggregate balance shown above includes those amounts, both executive contributions and registrant contributions, that have been disclosed either as base salary as described in Note 1 or as company contributions under all other compensation as described in Note 2 for the current fiscal year. In 2007, all participants in the deferred compensation plan were eligible to receive a distribution of their entire account balance in the plan accumulated through December 31, 2006. Messrs. Rowe, Hilzinger, Barnett, Crane, Pardee, Galvanoni, Clark, McDonald, Trpik, Mitchell, Donnelly and Ms. Moler elected to receive this distribution. Messrs. Cornew, Adams, Bonney, Acevedo, and Ms. Pramaggiore do not participate in the plan.

Since receiving a distribution of their entire accumulated balance in 2007, all executive contributions which are included in the aggregate balance at fiscal year end have been included in base salary in the Summary Compensation Table for each year, and all registrant contributions that are included in the aggregate balance at fiscal year end have been included in all other compensation in the Summary Compensation Table for each year for Messrs. Rowe, Hilzinger, Barnett, Crane, Pardee, Galvanoni, Clark, McDonald, Mitchell and Ms. Moler.

For Messrs. O’Brien, McLean and Hooker, who did not elect to receive the distribution of their accumulated plan balance in 2007, the following amounts consisting of both executive contributions and registrant contributions have been included in the Summary Compensation Table either as either base salary or all other compensation for prior years where these individuals have been included as NEOs: $847,092; $235,747; and $40,915 respectively.

Potential Payments upon Termination or Change in Control

Employment Agreement with Mr. Rowe

Under the third 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 December 31, 2012.

If, prior to July 1, 2011, 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 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 annual incentive for the year in which his employment terminates based on the lesser of (1) the annual incentive that would have been paid based on actual performance without application of negative discretion to reduce the amount of the award, and (2) the formula annual incentive (i.e., the greater of 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);

•

a lump sum severance payment equal to his base salary and the formula annual incentive, multiplied by the number of years (including fractional years) remaining until the later of July 1, 2011 or the first anniversary of the termination date.

•

continuation of life, disability, accident, health and other active welfare benefits for him and his family for a period equal to the number of years (including fractional years) remaining until the later of July 1, 2011 or the first anniversary of the termination date, followed by post-retirement healthcare 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;

•

non-vested stock options become exercisable and thereafter remain exercisable until the applicable option expiration date;

•

previously earned but non-vested performance share units vest, consistent with the terms of the performance share unit award program under the LTIP, and an award based on actual performance for the year in which the termination occurs; and

•

any non-vested restricted stock award vests.

392

If such a 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 July 1, 2011 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, then Mr. Rowe would receive the termination benefits described above except that:

•

the annual incentive award described above and payable for the year in which Mr. Rowe’s employment terminates will be paid in full, rather than prorated;

•

in determining the amount of such full formula annual incentive and the lump sum severance payment described above, 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, but not greater than the annual incentive for the year in which the termination occurs based on actual performance without the application of negative discretion to reduce the amount of the award;

•

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 public 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 July 1, 2011.

With respect to a termination of employment during the Change in Control or Significant Acquisition periods described above, the following events will constitute additional grounds for termination for good reason:

•

a good faith determination by Mr. Rowe that he is substantially unable to perform, or that there has been a material reduction in, any of his duties, functions, responsibilities or authority;

•

the failure of any successor to assume his employment agreement;

•

a relocation of Exelon’s principal offices 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.

In the event Mr. Rowe’s employment terminates for cause, all outstanding stock options (whether vested or non-vested), non-vested performance shares and restricted stock will be forfeited. Upon a termination for cause on or before March 16, 2010 (the retirement date specified under a prior agreement), the portion of the SERP benefit that accrued after March 16, 2006 (the retirement date specified under his original agreement) also will be forfeited.

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).

393

Upon Mr. Rowe’s retirement or his termination of employment due to disability or death:

•

Mr. Rowe (or his beneficiary or estate) will receive a prorated annual incentive for the year in which the termination occurs, determined under the method described above for a “good reason” termination;

•

all exercisable stock options remain exercisable until the applicable option expiration date;

•

non-vested stock options become exercisable and thereafter remain exercisable until the applicable option expiration;

•

previously earned but non-vested performance share units vest, consistent with the terms of the performance share award program under the LTIP, and he (or his beneficiary or estate) will receive an award for the year in which the termination occurs;

•

any non-vested restricted stock award vests, unless otherwise provided in the grant instrument; and

•

he will be entitled to receive post-retirement healthcare coverage for him and his wife for the remainder of their respective lives.

The term “retirement” means:

•

Mr. Rowe’s termination of employment prior to July 1, 2011 other than a termination by him for good reason or a termination by the Company with or without cause or upon disability or death;

•

Mr. Rowe’s termination of employment on or after July 1, 2011 other than a termination by the Company with cause or upon disability or death.

Upon Mr. Rowe’s retirement or termination of employment for any reason other than cause, disability or death:

•

For a period of five years, Mr. Rowe is required to attend board of directors meetings as requested by the board or the then-chairman, attend civic, charitable and corporate events, serve on civic and charitable boards and represent the Company at industry and trade association events as the Company’s representative, and provide the then-chairman or the then-CEO advice or counseling on energy policy issues or strategy, each as mutually agreed;

•

The Company is required to provide Mr. Rowe with five years of office and secretarial services.

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, and is required to sign a general release to receive severance payments. If the payments or benefits payable to Mr. Rowe would be subject to excise taxes imposed under Section 4999 of the Internal Revenue Code on excess parachute payments or under similar state or local law, Mr. Rowe may elect to reduce or eliminate such payments and benefits to the extent necessary to avoid such excise taxes. If any payment to Mr. Rowe would be subject to a penalty under Section 409A of the Internal Revenue Code, Exelon payment of such amount will be delayed by six months after the termination date, and his agreement will be otherwise interpreted and construed to comply with Section 409A.

Change in control employment agreements and severance plan covering other named executives

Exelon’s change in control and severance benefits policies were initially adopted in January 2001 and harmonized the policies of Exelon’s predecessor companies. In adopting the policies, the

compensation committee considered the advice of a consultant who advised that the levels were consistent with competitive practice and reasonable. The Exelon benefits include multiples of change in control benefits ranging from two times base salary and annual bonus for corporate and subsidiary vice presidents to 2.99 times base salary and annual bonus for the executive committee and select

394

senior vice presidents other than the CEO. In 2003, the compensation committee reviewed the terms of the Senior Management Severance Plan and revised it to reduce the situations when an executive could terminate and claim severance benefits for “good reason”, clarified the definition of “cause”, and reduced non-change in control benefits for executives with less than two years of service. In December 2004, the compensation committee’s consultant presented a report on competitive practice on executive severance. The competitive practices described in the report were generally comparable to the benefits provided under Exelon’s severance policies. In discussing the compensation consultant’s December 2007 annual report to the committee on compensation trends, the consultant commented that Exelon’s change in control and severance policies were conservative, citing the use of double triggers, and that they remained competitive.

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 annual incentive and performance share unit awards for the year in which termination occurs;

•

severance payments equal to 2.99 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, but not more than the annual incentive for the year of termination based on actual performance before the application of negative discretion;

•

a benefit equal to the amount payable under the SERP determined as if (1) the SERP benefit were fully vested, (2) the executive had 2.99 additional years of age and years of service (2.0 years for executives who first entered into such agreements after 2003) and (3) the severance pay constituted covered compensation for purposes of the SERP;

•

a benefit equal to the actuarial equivalent present value of any non-vested accrued benefit under Exelon’s qualified defined benefit retirement plan;

•

all previously-awarded stock options, performance shares or units, restricted stock, or restricted share units become fully vested, and the stock 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 on the same terms and conditions applicable to active employees, 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).

395

A change in control generally occurs:

•

when any person acquires 20% of Exelon’s voting securities;

•

when the incumbent members of the Exelon board of directors (or new members nominated by a majority of incumbent directors) cease to constitute at least a majority of the members of the Exelon board of directors;

•

upon consummation of a reorganization, merger or consolidation, or sale or other disposition of at least 50% of Exelon’s operating assets (excluding a transaction where Exelon shareholders retain at least 60% of the voting power); or

•

upon shareholder approval of a plan of complete liquidation or dissolution.

The term good reason under the change in control employment agreements generally includes any of the following occurring within 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 other than Mr. Rowe who have entered into such change in control employment agreements prior to April 2, 2009 (and which have not been materially amended after such date) 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, but only 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 is less than 110% of the safe harbor amount, then payments and benefits subject to these taxes would be reduced or eliminated to equal the safe harbor amount.

396

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 annual incentive and performance share unit awards for the year in which termination occurs;

•

for a two-year severance period, continued payment of an amount representing base salary and target annual incentive;

•

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 on the same terms and conditions applicable to active employees, 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.

Benefits under the change in control employment agreements and the Senior Management Severance Plan are subject to termination upon an executive’s violation of his or her restrictive covenants, and incentive payments under the agreements and the plan are subject to the recoupment policy adopted by the Compensation Committee of the Board of Directors.

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 31, 2009. 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.

397

Exelon, Generation and PECO


Name	Cash Payment ($) Note (1)		Value of Unvested Equity Awards ($) Note (2)		Perquisites and Other Benefits ($) Note (4)		Total Value of All Payments and Benefits ($) Note (5)
Rowe	$	1,574,000	$	8,465,000	$	1,500,000	$	11,539,000
O’Brien		—		—		—		—
Hilzinger		—		—		—		—
Barnett		—		—		—		—
Crane		680,000		2,314,000		—		2,994,000
McLean		437,000		2,021,000		—		2,458,000
Moler		282,000		1,688,000		—		1,970,000
Pardee		—		—		—		—
Cornew		—		—		—		—
Adams		165,000		616,000		—		781,000
Bonney		121,000		454,000		—		575,000
Acevedo		—		—		—		—
Galvanoni		—		—		—		—

ComEd


Name	Cash Payment ($) Note (1)		Value of Unvested Equity Awards ($) Note (2)		Value of ComEd Cash Based LTIP Awards ($) Note (3)		Perquisites and Other Benefits ($) Note (4)		Total Value of All Payments and Benefits ($) Note (5)
Clark	$	425,000	$	—	$	2,676,000	$	—	$	3,101,000
Trpik		—		—		—		—		—
Pramaggiore		249,000		—		1,109,000		—		1,358,000
Hooker		182,000		—		822,000		—		1,004,000
Donnelly		—		—		—		—		—

(1)

Under the terms of the 2009 AIP, a pro-rated actual incentive award is payable upon retirement assuming an IPM of 100% and based on the number of days worked during the year of retirement. Pursuant to Section 7.4(a) of his employment agreement, Mr. Rowe is entitled to a pro-rata portion of the lesser of his (i) actual annual incentive in the year of retirement (determined before the application of negative discretion by the board of directors) or (ii) Formula Annual Incentive, based on days worked during the year of retirement. Incentive calculations assume an IPM of 100% for the termination year.

(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 31, 2009, which was $48.87 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 31, 2009 closing price of Exelon stock.

(3)

The value of cash based LTIP awards includes the value of earned and unvested award amounts and unearned award amounts. Pursuant to the ComEd LTIP, participants receive a pro-rated incentive award for the year of termination, if termination occurs due to retirement. Since the SEC rules indicate registrants are to assume the termination occurred on the last business day of the fiscal year, the unearned award amount represents the executive’s 2009 target award.

(4)	Represents the estimated value of (i) five years of office and secretarial services (at an assumed cost of $300,000/yr), which is to be provided pursuant to Section 7.7 of Mr. Rowe’s employment agreement.

(5)	The estimate of total payments and benefits is based on a December 31, 2009 retirement date.

398

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 31, 2009. 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 ($) Note (1)		Value of Unvested Equity Awards ($) Note (2)		Perquisites and Other Benefits ($)		Total Value of All Payments and Benefits ($) Note (4)
Rowe	$	1,574,000	$	8,465,000	$	—	$	10,039,000
O’Brien		396,000		1,560,000		—		1,956,000
Hilzinger		262,000		1,018,000		—		1,280,000
Barnett		154,000		518,000		—		672,000
Crane		680,000		3,780,000		—		4,460,000
McLean		437,000		2,510,000		—		2,947,000
Moler		282,000		1,688,000		—		1,970,000
Pardee		338,000		1,810,000		—		2,148,000
Cornew		223,000		986,000		—		1,209,000
Adams		165,000		811,000		—		976,000
Bonney		121,000		454,000		—		575,000
Acevedo		74,000		116,000		—		190,000
Galvanoni		79,000		378,000		—		457,000

ComEd


Name	Cash Payment ($) Note (1)		Value of Unvested Equity Awards ($) Note (2)		Value of ComEd Cash Based LTIP Awards ($) Note (3)		Perquisites and Other Benefits ($)		Total Value of All Payments and Benefits ($) Note (4)
Clark	$	425,000	$	—	$	2,676,000	$	—	$	3,101,000
Trpik		126,000		345,000		133,000		—		604,000
Pramaggiore		249,000		196,000		1,109,000		—		1,554,000
Hooker		182,000		—		822,000		—		1,004,000
Donnelly		193,000		324,000		739,000		—		1,256,000

(1)

Officers receive a pro-rated annual incentive award assuming an IPM of 100% and based on the number of days worked during the year of termination due to death or disability. Mr. Rowe would generally be entitled to a pro-rated portion of the lesser of his Formula Annual Incentive as specified by his employment agreement or the annual incentive for the year of termination (determined before application of negative discretion by the board of directors). 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, and (iii) the average annual incentive paid for the three years prior to the year of termination. Incentive calculations assume an IPM of 100% for the termination year. Upon disability, Messrs. Crane and Pardee would be eligible for an additional pension benefit of $6,387 and $5,651, respectively, per month for the remainder of their lives commencing upon exhaustion of their LTD benefits.

(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 termination, and, if

399

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 31, 2009, which was $48.87, 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 31, 2009 closing price of Exelon stock.

(3)

(4)	The estimate of total payments and benefits is based on a December 31, 2009 termination date due to death or disability.

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 31, 2009 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 ($) Note (1)		Retirement Benefit Enhance- ment ($) Note (2)		Value of Unvested Equity Awards ($) Note (3)		Health and Welfare Benefit Continuation ($) Note (5)		Perquisites and Other Benefits ($) Note (6)		Total Value of All Payments and Benefits ($) Note (7)
Rowe	$	6,470,000	$	2,443,000	$	8,465,000	$	225,000	$	1,500,000	$	19,103,000
O’Brien		2,272,000		138,000		1,560,000		74,000		40,000		4,084,000
Hilzinger		1,332,000		78,000		843,000		22,000		40,000		2,315,000
Barnett		735,000		43,000		518,000		16,000		40,000		1,352,000
Crane		3,733,000		2,828,000		2,948,000		87,000		40,000		9,636,000
McLean		2,627,000		154,000		2,206,000		127,000		40,000		5,154,000
Moler		1,834,000		524,000		1,688,000		100,000		40,000		4,186,000
Pardee		2,168,000		492,000		1,459,000		27,000		40,000		4,186,000
Cornew		1,523,000		98,000		811,000		21,000		40,000		2,493,000
Adams		1,163,000		74,000		671,000		28,000		40,000		1,976,000
Bonney		621,000		304,000		454,000		14,000		40,000		1,433,000
Acevedo		439,000		28,000		42,000		14,000		40,000		563,000
Galvanoni		467,000		29,000		329,000		15,000		40,000		880,000

400

ComEd


Name	Cash Payment ($) Note (1)		Retirement Benefit Enhance- ment ($) Note (2)		Value of Unvested Equity Awards ($) Note (3)		Value of ComEd Cash Based LTIP Awards ($) Note (4)		Health and Welfare Benefit Continuation ($) Note (5)		Perquisites and Other Benefits ($) Note (6)		Total Value of All Payments and Benefits ($) Note (7)
Clark	$	2,410,000	$	970,000	$	—	$	2,676,000	$	88,000	$	40,000	$	6,184,000
Trpik		634,000		36,000		296,000		133,000		10,000		40,000		1,149,000
Pramaggiore		1,245,000		70,000		91,000		1,109,000		22,000		40,000		2,577,000
Hooker		1,205,000		605,000		—		822,000		34,000		40,000		2,706,000
Donnelly		871,000		47,000		219,000		739,000		17,000		40,000		1,933,000

(1)

The cash payment is composed of payment equal to a specified multiple of the NEO’s base salary plus a pro-rated annual incentive award assuming an IPM of 100% and based on the number of days worked in the year of termination. Other than Mr. Rowe, the executives are participants in the Senior Management Severance Plan (“SMSP”) and severance benefits are determined pursuant to Section 4 of the Severance Plan. Pursuant to Section 7.3(a) of his employment agreement, Mr. Rowe is entitled to a pro-rata portion of the lesser of his (i) actual annual incentive in the year of termination (determined before the application of negative discretion by the board of directors) or (ii) Formula Annual Incentive, based on days worked during the year of termination. Incentive calculations assume an IPM of 100% for the termination year. For all other officers except Messrs. Hilzinger, Barnett, Bonney, Acevedo, Galvanoni, Trpik, Donnelly and Ms. Pramaggiore, the multiple used for base salary and annual incentive is 2. For Messrs. Barnett, Bonney, Acevedo, Galvanoni, Trpik, and Donnelly the multiple is 1.25 and for Mr. Hilzinger and Ms. Pramaggiore the multiple is 1.5. For Mr. Rowe, the severance benefit is equal to 1.5 times the sum of his (i) current base salary and (ii) Formula Annual Incentive.

(2)

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 severance pay period was taken into account for purposes of vesting, and the severance pay constituted covered compensation for purposes of the non-qualified pension plan.

(3)

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 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 31, 2009, which was $48.87, 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 31, 2009 closing price of Exelon stock.

(4)

(5)	Estimated costs of heath care, life insurance, and long-term disability coverage which continue during the severance period.

(6)	Estimated costs of outplacement services for 12 months for all NEOs except Mr. Rowe. Pursuant to Section 7.7 of Mr. Rowe’s employment agreement, he would receive five years of office and secretarial services (at an assumed cost of $300,000/yr).

(7)	The estimate of total payments and benefits is based on a December 31, 2009 termination date.

401

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, 2009. The company has entered into Change in Control agreements with Messrs. Clark, Cornew, Crane, McLean, O’Brien and Pardee and Ms. Moler. 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. Mr. Rowe’s employment agreement includes change in control provisions similar to those for the other NEOs. See Potential Payments upon Termination or Change in Control—Employment Agreement with Mr. Rowe for additional information.

Exelon, Generation and PECO


Name	Cash Payment ($) Note ⁽¹⁾		Retirement Benefit Enhance- ment ($) Note ⁽²⁾		Value of Unvested Equity Awards ($) Note ⁽³⁾		Health and Welfare Benefit Continuation ($) Note ⁽⁵⁾		Perquisites and Other Benefits ($) Note ⁽⁶⁾		Excise Tax Gross-up Payment / Scale- back Note ⁽⁷⁾	Total Value of All Payments and Benefits ($) Note ⁽⁸⁾
Rowe	$	6,147,000	$	3,401,000	$	8,465,000	$	225,000	$	1,540,000	Ineligible	$	19,778,000
O’Brien		3,382,000		139,000		1,560,000		111,000		40,000	Not Required		5,232,000
Hilzinger		1,752,000		104,000		1,018,000		30,000		40,000	Ineligible		2,944,000
Barnett		1,143,000		69,000		713,000		25,000		40,000	Ineligible		1,990,000
Crane		5,264,000		3,848,000		3,780,000		131,000		40,000	Not Required		13,063,000
McLean		3,743,000		230,000		2,510,000		191,000		40,000	Not Required		6,714,000
Moler		2,790,000		794,000		1,688,000		149,000		40,000	Not Required		5,461,000
Pardee		3,301,000		605,000		2,201,000		41,000		40,000	Not Required		6,188,000
Cornew		2,355,000		147,000		1,182,000		32,000		40,000	Not Required		3,756,000
Adams		1,229,000		74,000		811,000		28,000		40,000	Ineligible		2,182,000
Bonney		989,000		406,000		454,000		23,000		40,000	Ineligible		1,912,000
Acevedo		710,000		45,000		116,000		22,000		40,000	Ineligible		933,000
Galvanoni		750,000		47,000		378,000		24,000		40,000	Ineligible		1,239,000

402

ComEd


Name	Cash Payment ($) Note (1)		Retirement Benefit Enhance- ment ($) Note (2)		Value of Unvested Equity Awards ($) Note (3)		Value of ComEd Cash Based LTIP Awards ($) Note (4)		Health and Welfare Benefit Continuation ($) Note (5)		Perquisites and Other Benefits ($) Note (6)		Excise Tax Gross-Up Payment / Scale- back Note (7)	Total Value of All Payments and Benefits ($) Note (8)
Clark	$	3,572,000	$	1,070,000	$	—	$	2,676,000	$	133,000	$	40,000	Not Required	$	7,491,000
Trpik		950,000		58,000		345,000		133,000		17,000		40,000	Ineligible		1,543,000
Pramaggiore		1,577,000		93,000		440,000		1,109,000		29,000		40,000	Ineligible		3,288,000
Hooker		1,205,000		605,000		—		822,000		34,000		40,000	Ineligible		2,706,000
Donnelly		1,278,000		76,000		519,000		739,000		28,000		40,000	Ineligible		2,680,000

(1)

Cash payment includes a severance payment and the NEO’s annual incentive for the year of termination assuming an IPM of 100%. With the exception of Messrs. Rowe, Hilzinger, Barnett, Adams, Bonney, Acevedo, Galvanoni, Trpik, Hooker, Donnelly and Ms. Pramaggiore the severance benefit is equal to 2.99 times the sum of the executive’s (i) current base salary and (ii) Severance Incentive. For Messrs. Hilzinger, Barnett, Adams, Bonney, Acevedo, Galvanoni, Trpik, Hooker, Donnelly and Ms. Pramaggiore the severance benefit is equal to 2.0 times the sum of the executive’s (i) current base salary and (ii) Severance Incentive. Also includes an additional payment for Dennis O’Brien of $35,000. For Mr. Rowe, the severance benefit is equal to 1.5 times the sum of his (i) current base salary and (ii) Formula Annual Incentive.

The Severance Incentive is defined as the greater of the (i) target annual incentive for the year of termination and (ii) the average annual incentive paid for the two years prior to the year of termination (i.e., the 2007 and 2008 actual annual incentives).

Mr. Rowe’s Formula Annual Incentive is defined is defined as the greater of the (i) 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 2006, 2007, and 2008 actual annual incentives). For purposes of a Special Termination, the Formula Annual Incentive is defined as the lesser of (i) the greater of the Formula Annual Incentive or the target annual incentive for the year of termination and (ii) the actual annual incentive paid for the latest calendar year ended on or before the termination date (determined before the application of negative discretion by the board of directors). Incentive calculations assume an IPM of 100% for the termination year.

(2)	Represents the estimated retirement benefit enhancement.

(3)

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 due to a change in control, 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 that may vest upon 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 31, 2009, which was $48.87, 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 31, 2009 closing price of Exelon stock.

(4)

(5)	Health and welfare benefits (i.e., healthcare, life insurance and long-term disability) are continued during the severance period.

(6)	Executives receive outplacement services for up to 12 months. Pursuant to Section 7.7 of Mr. Rowe’s employment agreement Mr. Rowe would receive five years of office and secretarial services (at an assumed cost of $300,000/yr.)

(7)

Represents the estimated value of the required excise tax gross-up payment or scaleback, if applicable. All of the executives, with the exception of Messrs. Rowe, Hilzinger, Barnett, Adams, Bonney, Acevedo, and Galvanoni, are entitled to an excise tax gross-up payment under their CIC 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.

(8)	The estimate of total payments and benefits is based on a December 31, 2009 termination date.

403

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. One employee director, Mr. Rowe, not shown in the table, receives 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 Note 2	Total
	Committee Membership	Annual Board & Committee Retainers		Board & Committee Meeting Fees		Stock Awards			Total
John A. Canning, Jr.	A, C	$	55,000	$	54,000	$	100,000	—	$	209,000
M. Walter D’Alessio	G (ch), C		60,000		48,000		100,000	—		208,000
Nicholas DeBenedictis	G, E (ch), P		65,000		58,000		100,000	—		223,000
Bruce DeMars	A, G, E, P (ch)		70,000		80,000		100,000	—		250,000
Nelson A. Diaz	E, P, R		55,000		56,000		100,000	—		211,000
Sue L. Gin	A, G, R (ch)		65,000		68,000		100,000	—		233,000
Rosemarie B. Greco	C (ch), E		60,000		54,000		100,000	—		214,000
Paul L. Joskow	A, E, R		55,000		60,000		100,000	—		215,000
Richard W. Mies (Note 1)	A,P		52,258		36,000		91,389	—		179,647
John M. Palms (Note 3)	A (ch), G, P, R		70,000		82,000		100,000	—		252,000
William C. Richardson (Note 3)	A, C, G, R		55,000		80,000		100,000	—		235,000
Thomas J. Ridge	E		50,000		32,000		100,000	—		182,000
John W. Rogers, Jr.	G, R		50,000		46,000		100,000	—		196,000
Stephen D. Steinour	A, C, P		60,000		60,000		100,000	—		220,000
Donald Thompson	E, P		55,000		42,000		100,000	—		197,000

Total All Directors		$	877,258	$	856,000	$	1,491,389	—	$	3,224,647

Committee Membership Key

Audit = A, Chairman = Ch, Compensation = C, Corporate Governance = G, Energy Delivery

Oversight = E, Generation Oversight = P, Risk Oversight = R

Notes:

(1)	Admiral Mies was appointed to the board on February 2, 2009 and all retainers were pro-rated from this date.

(2)

Values in this column represent that portion of the directors accrued earnings in their non-qualified deferred compensation account that were considered as above market. See the description below under the heading “Deferred Compensation.” For 2009, none of the directors recognized any such earnings.

(3)

In addition to the amounts shown in the table, Drs. Palms and Richardson, who also serve as directors of the Exelon Foundation, received $6,000 and $8,000, respectively, from the Foundation for attending meetings of the Foundation’s board. Exelon contributes to the Foundation to pay for the Foundation’s operating expenses.

Fees Earned or Paid in Cash

The Exelon board has a policy of targeting their compensation to the median board compensation of the same peer group of companies used to benchmark executive compensation. All directors receive an annual retainer of $50,000 paid in cash. Committee chairs receive an additional $10,000 per year, and members of the audit committee and generation oversight committee, including the committee chairs, receive an additional $5,000 per year for their participation on these committees.

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Directors receive $2,000 for each meeting of the board or board committee that they attend, whether in person or by means of teleconferencing or video conferencing equipment. Directors also receive a $2,000 meeting fee for attending the annual shareholders meeting and the annual strategy retreat.

Stock Awards

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. Directors are required under the Exelon Corporate Governance Principles to own 5,000 shares of Exelon common stock or deferred stock units within five years after their election to the board.

Directors receive deferred stock units worth $100,000 per year. Deferred stock units are granted and credited to a notional account maintained on the books of the corporation 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 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, 2009, 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, 2009, which was $48.87. Legacy plans include those stock units earned from Exelon’s predecessor companies, PECO Energy Company and Unicom Corporation. For Adm. DeMars and Mr. Rogers, the legacy deferred stock units reflect accrued benefits from the Unicom Directors Retirement Plan (which was terminated in 1997) and the Unicom 1996 Directors Fee Plan (which was terminated in 2000), respectively.


	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 12/31/09 $
John A. Canning	2008		2,862	2,862	$	139,866
M. Walter D’Alessio	1983		11,245	11,245		549,543
Nicholas DeBenedictis	2002		8,926	8,926		436,214
Bruce DeMars	1996	1,332	3,548	4,880		238,486
Nelson A. Diaz	2004		8,803	8,803		430,203
Sue L. Gin	1993		3,548	3,548		173,391
Rosemarie B. Greco	1998		13,016	13,016		636,092
Paul L. Joskow	2007		4,048	4,048		197,826
Richard W. Mies	2009		1,913	1,913		93,488
John M. Palms	1990		8,926	8,926		436,214
William C. Richardson	2005		7,051	7,051		344,582
Thomas J. Ridge	2005		6,802	6,802		332,414
John W. Rogers, Jr	1999	3,590	16,239	19,829		969,043
Stephen D. Steinour	2007		4,317	4,317		210,972
Donald Thompson	2007		4,317	4,317		210,972

Total All Directors		4,922	105,561	110,483	$	5,399,306

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)

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will be settled in cash and may be distributed in a lump sum or in annual installment payments upon a director’s reaching age 65, age 72 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 have one additional fund not available to employees that, through its composition, provides returns that can be in excess of 120% of the Federal long-term rate that is used by the IRS to determine above market returns. However, during 2009 none of the directors had investments in this fund.

Other Compensation

Exelon pays the cost of a director’s spouse’s travel, meals, lodging and related activities 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 activities 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 activities and to reimburse the director for the taxes on the imputed income. In 2009, incremental cost to the company to provide these perquisites was less than $10,000 per director and the aggregate amount for all directors as a group, a total of 15 directors, was $14,604. The aggregate amount paid to all directors as a group (15 directors) for reimbursement of taxes on imputed income was $10,949.

Exelon has a board compensation and expense reimbursement policy under which directors are reimbursed for reasonable travel to and from their primary residence and lodging expenses incurred when attending board and committee meetings or other events on behalf of Exelon, (including director’s orientation or continuing education programs, facility visits or other business related activities for the benefit of Exelon). Under the policy, Exelon will arrange for its corporate aircraft to transport groups of directors, or when necessary, individual directors, to meetings in order to maximize the time available for meetings and discussion. Directors may bring their spouses on Exelon’s corporate aircraft when they are invited to an Exelon event, and the value of this travel, calculated according to IRS regulations, is imputed to the director as additional taxable income. Exelon has a matching gift program available to directors and officers that matches their contributions to educational institutions up to $5,000 per year and a matching gift program for other employees that matches their contributions to educational institutions up to $2,000 per year.

Generation

Generation does not have a board of directors.

406

ComEd

For their service as directors of the company, ComEd’s non-employee directors receive the compensation shown in the following table and explained in the accompanying notes. Mr. Clark and Mr. Rowe, not shown in the table, receive no additional compensation for their service as directors.


	Committee Membership	Fees Earned or Paid in Cash				Total
	Committee Membership	Annual Board & Committee Retainers		Board & Committee Meeting Fees		Total
James W. Compton	A	$	70,000	$	26,000	$	96,000
Peter V. Fazio, Jr.			70,000		26,000		96,000
Sue L. Gin	A		—		26,000		26,000
Edgar D. Jannotta	A		70,000		20,000		90,000
Edward J. Mooney			70,000		24,000		94,000
Michael H. Moskow			70,000		14,000		84,000
John W. Rogers, Jr.	A (ch)		—		22,000		22,000
Jesse H. Ruiz			70,000		14,000		84,000
Richard L. Thomas			70,000		38,000		108,000

Total All Directors		$	490,000	$	210,000	$	700,000

Committee Membership Key

Audit = A, Operating = O; Chairman = Ch

Fees Earned or Paid in Cash

Non-employee directors of the ComEd board receive an annual retainer of $70,000 paid quarterly in arrears. Members of the ComEd board who are also members of the Exelon board do not receive this retainer. All non-employee directors receive $2,000 for each board or committee meeting attended whether in person or by means of teleconferencing or video conferencing equipment.

The ComEd board does not grant any type of equity awards and does not have a deferred compensation plan.

Other Compensation

ComEd pays the cost of a director’s spouse’s travel and meals when the spouses are invited to attend Exelon, ComEd or industry related events where it is customary and expected that directors attend with their spouses. The cost of such travel and meals is imputed to the director as additional taxable income. However, in most cases there is no incremental cost to ComEd of providing travel for a director’s spouse when he or she accompanies the director, and the only additional costs to ComEd are those for meals and other minor expenses and to reimburse the director for the taxes on the imputed income. In 2009, the incremental cost to ComEd to provide these perquisites was less than $10,000 per director and the aggregate amount for all directors as a group, a total of 9 directors was $2,651. The aggregate amount paid to all directors as a group (9 directors) for reimbursement of taxes on imputed income was $1,469.

PECO

For their service as directors of the company, PECO’s non-employee directors receive the compensation shown in the following table and explained in the accompanying notes. Two employee directors, Mr. O’Brien and Mr. Rowe, not shown in the table, receive no additional compensation for their service as directors.

407

In July 2008, the PECO board voted to reduce its size to seven members. At the same time it also established an Executive Committee to assist the board in its management and oversight duties and to act on behalf of the board when the full board was not in session. Mr. O’Brien, Mr. Rowe, and Mr. D’Alessio were appointed to this committee.


		Fees Earned or Paid in Cash
	Committee Membership	Annual Board & Committee Retainers		Board & Committee Meeting Fees		Total
M. Walter D’Alessio	E	$	—	$	10,000	$	10,000
Nelson A. Diaz			—		10,000		10,000
Rosemarie B. Greco			—		8,000		8,000
Thomas J. Ridge			—		8,000		8,000
Ronald Rubin			70,000		8,000		78,000

Total All Directors		$	70,000	$	44,000	$	114,000

Committee Membership Key

E = Executive Committee

Fees Earned or Paid in Cash

Non-employee members of the PECO board receive an annual retainer of $70,000 paid quarterly in arrears. Members of the PECO board who are also members of the Exelon board do not receive this retainer. Non-employee directors receive $2,000 for each board or committee meeting attended whether in person or by means of teleconferencing or video conferencing equipment.

The PECO board does not grant any type of equity awards and does not have a deferred compensation plan.

408

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, 2009 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 (Note 1)	Vested Stock Options and Options that Vest Within 60 days	Total Shares Held	Share Equivalents to be Settled in Cash or Stock (Note 2)	Total Share Interest
Directors
John A. Canning, Jr.	5,000	2,862	—	7,862	876	8,738
M. Walter D’Alessio ⁽³⁾	12,366	11,245	—	23,611	—	23,611
Nicholas DeBenedictis	—	8,926	—	8,926	—	8,926
Bruce DeMars	10,671	4,880	—	15,551	—	15,551
Nelson A. Diaz ⁽³⁾	1,500	8,803	—	10,303	2,508	12,811
Sue L. Gin	45,973	3,548	—	49,521	4,657	54,178
Rosemarie B. Greco ⁽³⁾	2,000	13,016	—	15,016	9,655	24,671
Paul L. Joskow	2,000	4,048	—	6,048	4,779	10,827
Richard W. Mies ⁽⁵⁾	—	1,913	—	1,913	—	1,913
John M. Palms	—	8,926	—	8,926	—	8,926
William C. Richardson	1,347	7,051	—	8,398	—	8,398
Thomas J. Ridge ⁽³⁾	—	6,803	—	6,803	3,942	10,745
John W. Rogers, Jr.	11,374	19,829	—	31,203	10,894	42,097
Ronald Rubin ⁽⁴⁾	4,748	—	—	4,748	638	5,386
Stephen D. Steinour	4,295	4,317	—	8,612	5,231	13,843
Donald Thompson	—	4,317	—	4,317	3,755	8,072
Named Officers
John W. Rowe	301,915	6,456	437,250	745,621	118,696	864,317
Denis P. O’Brien	27,044	6,559	158,925	192,528	23,338	215,866
Matthew F. Hilzinger	11,380	5,569	46,100	63,049	10,706	73,755
Phillip S. Barnett	7,270	4,000	33,750	45,020	7,577	52,597
Christopher M. Crane	31,967	30,000	106,500	168,467	29,899	198,366
Ian P. McLean	43,649	15,363	425,438	484,450	29,616	514,066
Elizabeth A. Moler	26,433	—	105,675	132,108	23,864	155,972
Charles G. Pardee	16,957	18,000	67,300	102,257	18,541	120,798
Kenneth W. Cornew	10,366	9,000	31,576	50,942	9,609	60,551
Craig L. Adams	2,205	4,000	33,450	39,655	8,217	47,872
Paul R. Bonney	12,810	—	30,050	42,860	6,216	49,076
Jorge Acevedo	2,811	1,522	12,800	17,133	—	17,133
Matthew Galvanoni	3,645	3,000	18,075	24,720	3,217	27,937
Total
Directors & Executive Officers as a group, 33 people. (See Note 6)	662,924	277,676	1,712,564	2,653,164	394,999	3,048,163

(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.

409

(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)	Messrs. D’Alessio, Diaz and Ridge, and Ms. Greco, are directors of Exelon and PECO.

(4)	Mr. Rubin is a director of PECO.

(5)	Adm. Mies was elected to the board effective February 2009. He has until February 2014 to achieve his stock ownership requirement of 5,000 shares.

(6)

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. Total includes share holdings from all directors and NEOs as well as those executive officers listed in Item 1, Executive Officers of the Registrants, who are not NEOs for purposes of compensation disclosure.

Other significant owners of Exelon stock

Shown in the table below are those owners who are known to Exelon to hold more than 5% of the outstanding common stock. This information is based on the most recent Schedule 13G filed by each owner with the SEC on February 13, 2009.


Name and address of beneficial owner	Amount and nature of beneficial ownership	Percent of class
Capital World Investors	32,994,000	5	%
333 South Hope Street Los Angeles, California 90071

Capital Research Global Investors	39,237,320	6	%
333 South Hope Street Los Angeles, California 90071

Capital World Investors and Capital Research Global Investors are each divisions of Capital Research and Management Company. Capital World Investors disclosed in its Schedule 13G that it disclaims beneficial ownership of all shares and it has sole voting power over 734,000 shares and sole dispositive power over all shares. Capital Research Global Investors disclosed in its Schedule 13G that it disclaims beneficial ownership of all shares and it has sole voting power over 25,451,720 shares and sole dispositive power over all shares.

Stock Ownership Requirements for Directors and Officers

Under Exelon’s Corporate Governance Principles, all directors are required to own within five years after election to the board at least 5,000 shares of Exelon common stock or deferred stock units or shares accrued in the Exelon common stock fund of the directors’ deferred compensation plan. The corporate governance committee utilized an independent compensation consultant who determined that, compared to its peer group, Exelon’s ownership requirement is reasonable.

Officers of Exelon (and its subsidiaries) are required to own certain amounts of Exelon common stock, depending on their seniority, 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 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 September 30, 2009 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

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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 stock options do not count for this purpose. As of December 31, 2009, the named executive officers (NEOs) held the following amounts of stock relative to the applicable guidelines:


Name	Ownership Multiple	Ownership Guideline in Shares	Share or Share Equivalents Owned	Ownership As a Percent of Guideline
John W. Rowe	5X	107,920	427,067	396	%
Denis P. O’Brien	3X	17,494	56,941	325	%
Matthew F. Hilzinger	2X	10,000	27,655	277	%
Phillip S. Barnett	2X	10,000	18,847	188	%
Christopher M. Crane	3X	21,868	91,866	420	%
Ian P. McLean	3X	22,165	88,628	400	%
Elizabeth A. Moler	3X	21,667	50,297	232	%
Charles G. Pardee	2X	12,950	53,498	413	%
Kenneth W. Cornew	2X	9,295	28,975	312	%
Craig L. Adams	2X	10,000	14,422	144	%
Paul R. Bonney	1X	4,000	19,026	476	%
Jorge A. Acevedo	1X	4,000	4,333	108	%
Matthew Galvanoni	1X	4,000	9,862	247	%

Securities Authorized for Issuance under Exelon Equity Compensation Plans


[A]	[B]	[C]		[D]
Plan Category	Number of securities to be issued upon exercise of outstanding options (Note 1)	Weighted-average price of outstanding options		Number of securities remaining available for future issuance under equity compensation plans (Note 3)
Equity compensation plans approved by security holders	13,858,846	$	49.94	22,500,000
Equity compensation plans not approved by security holders (Note 2)	10,166	$	23.11

Total	13,869,012			22,500,000

(1)

Includes stock options, unvested performance shares, unvested restricted shares that were granted under the Exelon LTIP or predecessor company plans and shares awarded under those plans and deferred into the stock deferral plan, as well as deferred stock units granted to directors as part of their compensation plan described in Item 11, Compensation of Non-employee Directors. See Note 16 of the Combined Notes to Consolidated Financial Statements for additional information.

(2)	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.

(3)	Excludes securities to be issued upon exercise of outstanding options and vesting of shares or deferred stock units shown in column [B].

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 Corporation 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, 2009 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.

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.”

411


	[A]	[B]	[C]	[D]=[A]+[B]+[C]	[E]	[F]=[D]+[E]
	Beneficially Owned Shares	Shares Held in Company Plans (Note 1)	Vested Stock Options and Options that Vest Within 60 days	Total Shares Held	Share Equivalents to be Settled in Cash or Stock (Note 2)	Total Share Interest
Directors
James W. Compton	6,000	—	—	6,000	—	6,000
Peter V. Fazio, Jr	—	—	—	—	—	—
Sue L. Gin	45,973	3,548	—	49,521	4,657	54,178
Edgar D. Jannotta	26,282	—	—	26,282	—	26,282
Edward J. Mooney	—	—	—	—	—	—
Michael H. Moskow	—	—	—	—	—	—
John W. Rogers, Jr.	11,374	19,829	—	31,203	10,894	42,097
John W. Rowe	301,915	6,456	437,250	745,621	118,696	864,317
Jess H. Ruiz	—	—	—	—	—	—
Richard L. Thomas	33,370	—	—	33,370	—	33,370

Named Officers
Frank M. Clark	27,601	—	66,000	93,601	2,839	96,440
Joseph R. Trpik, Jr.	4,874	3,305	13,725	21,904	3,192	25,096
Robert K. McDonald	10,379	—	34,250	44,629	173	44,802
Anne R. Pramaggiore	10,689	9,000	26,850	46,539	—	46,539
John T. Hooker	3,260	—	7,500	10,760	157	10,917
Terence R. Donnelly	15,058	9,132	66,675	90,865	3,092	93,957
J. Barry Mitchell	20,866	6,352	25,250	52,468	750	53,218
Total
Directors & Executive Officers as a group, 22 people.	633,789	117,152	968,888	1,719,829	158,616	1,878,445

(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)

412

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 2009 Exelon Proxy Statement.

Generation

There were no related person transactions involving Generation. Generation does not have an independent board of directors.

ComEd

Sidley Austin LLP provided legal services to Exelon and ComEd during 2009. The spouse of Mr. Ruiz, a member of the ComEd board of directors, 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. 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. The board determined that none of the relationships was material and accordingly that Messrs. Compton, Ruiz, Mooney, Fazio and Moskow are independent. Messrs. Rowe, Clark, Rogers, Jannotta, and Thomas and Ms. Gin are all current or former officers or directors of Exelon and accordingly are not independent.

PECO

There were no related person transactions involving PECO. Under PECO’s bylaws, an “independent director” is a director who is not a director, officer or employee of Exelon, PECO or any other Exelon Corporation affiliate (excluding for this purpose positions as directors of PECO or subsidiaries of PECO). All of the directors of PECO are not independent by virtue of being directors, officers or employees of Exelon or PECO, except for Ms. Lillie and Mr. Rubin.

413

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

Exelon

In July 2002, the Exelon Audit Committee adopted a policy for pre-approval of services to be performed by the independent accountants. The committee pre-approves annual budgets for audit, audit-related and tax compliance and planning services. The services that the committee will consider include services that do not impair the accountant’s independence and add value to the audit, including audit services such as attest services and scope changes in the audit of the financial statements, audit-related services such as accounting advisory services related to proposed transactions and new accounting pronouncements, the issuance of comfort letters and consents in relation to financings, the provision of attest services in relation to regulatory filings and contractual obligations, and tax compliance and planning services. With respect to non-budgeted services in amounts less than $500,000, the committee delegated authority to the committee’s chairman to pre-approve such services. All other services must be pre-approved by the committee. The committee receives quarterly reports on all fees paid to the independent accountants. None of the services provided by the independent accountants was provided pursuant to the de minimis exception to the pre-approval requirements contained in the SEC’s rules.

The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of Exelon’s annual financial statements for the years ended December 31, 2009 and 2008, 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)	2009		2008
Audit fees	$	9,515	$	9,424
Audit related fees^(a)		1,073		1,273
Tax fees^(b)		596		952
All other fees^(c)		25		51

^(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.

^(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 research and audit software licenses.

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 additional information regarding the Exelon and ComEd audit committees. In July 2002, the Exelon Audit Committee (the 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

414

comfort letters and consents in relation to financings, the provision of attest services in relation to regulatory filings and contractual obligations, and tax compliance and planning services. With respect to non-budgeted services in amounts less than $500,000, the Committee delegated authority to the Committee’s chairman to pre-approve such services. All other services must be pre-approved by the Committee. The Committee receives quarterly reports on all fees paid to the independent accountants. None of the services provided by the independent accountants was provided pursuant to the de minimis exception to the pre-approval requirements contained in the SEC’s rules.

The following 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, 2009 and 2008, 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)	2009		2008
Audit fees	$	4,160	$	4,199
Audit related fees^(a)		479		227
Tax fees^(b)		446		298
All other fees ^(c)		11		23

^(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.

^(c)	All other fees reflect work performed primarily in connection with research and audit software licenses.

ComEd


	Year Ended December 31,
(in thousands)	2009		2008
Audit fees	$	2,725	$	2,844
Audit related fees^(a)		308		156
Tax fees^(b)		62		326
All other fees ^(c)		7		14

^(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.

^(c)	All other fees reflect work performed primarily in connection with research and audit software licenses.

415

PECO


	Year Ended December 31,
(in thousands)	2009		2008
Audit fees	$	1,593	$	2,156
Audit related fees^(a)		177		63
Tax fees^(b)		79		299
All other fees ^(c)		4		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, tax planning and tax advice and consulting services in connection with appeals claims.

^(c)	All other fees reflect work performed primarily in connection with research and audit software licenses.

416

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES


(a)		Financial Statements and Financial Statement Schedules
(1)		Exelon
(i)		Financial Statements
		Consolidated Statements of Operations for the years 2009, 2008 and 2007
		Consolidated Statements of Cash Flows for the years 2009, 2008 and 2007
		Consolidated Balance Sheets as of December 31, 2009 and 2008
		Consolidated Statements of Changes in Shareholders’ Equity for the years 2009, 2008 and 2007
		Consolidated Statements of Comprehensive Income for the years 2009, 2008 and 2007
		Notes to Consolidated Financial Statements
(ii)		Financial Statement Schedule Schedule I Schedule II

417

EXELON CORPORATION AND SUBSIDIARY COMPANIES

Schedule I

Exelon Corporate

Statements of Operations


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Operating expenses
Operating and maintenance	$	45		$	19		$	51
Operating and maintenance from affiliates		35			31			31

Total operating expenses		80			50			82
Operating loss		(80	)		(50	)		(82	)

Other income and (deductions)
Interest expense, net of amounts capitalized		(133	)		(127	)		(144	)
Equity in earnings of investments		2,835			2,817			2,806
Interest Income from affiliates, net		—			2			2
Other, net		(42	)		9			26

Total other income and deductions		2,660			2,701			2,690

Income from continuing operations before income taxes		2,580			2,651			2,608
Income taxes		(127	)		(86	)		(128	)

Net income	$	2,707		$	2,737		$	2,736

See Notes to Financial Statements

418

Exelon Corporate

Condensed Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Net cash flows provided by operating activities	$	2,767		$	2,245		$	3,090

Cash flows from investing activities
Changes in Exelon intercompany money pool		31			(37	)		47
Change in note receivable from affiliate		—			—			67
Investment in affiliates		(454	)		(640	)		(871	)

Net cash flows used in investing activities		(423	)		(677	)		(757	)

Cash flows from financing activities
Change in short-term debt		(56	)		56			(150	)
Retirement of long-term debt		(500	)		—			—
Dividends paid on common stock		(1,385	)		(1,335	)		(1,180	)
Proceeds from employee stock plans		42			130			215
Purchase of treasury stock		—			(436	)		(1,208	)
Purchase of forward contract in relation to certain treasury stock		—			(64	)		(79	)
Other financing activities		7			61			105

Net cash flows used in financing activities		(1,892	)		(1,588	)		(2,297	)

Increase (decrease) in cash and cash equivalents		452			(20	)		36
Cash and cash equivalents at beginning of period		21			41			5

Cash and cash equivalents at end of period	$	473		$	21		$	41

See Notes to Financial Statements

419

Exelon Corporate

Balance Sheets


	December 31,
(In millions)	2009		2008
Assets
Current assets
Cash and cash equivalents	$	473	$	21
Accounts receivable, net
Other accounts receivable		108		105
Accounts receivable from affiliates		11		53
Notes receivables from affiliates		15		46

Total current assets		607		225

Property, plant and equipment, net		7		—
Deferred debits and other
Regulatory assets		2,613		2,829
Investments
Other investments		1		1
Investment in affiliates		16,313		15,848
Deferred income taxes		1,842		1,917
Mark-to-market derivative assets		10		17
Other		37		51

Total deferred debits and other assets		20,816		20,663

Total assets	$	21,430	$	20,888

See Notes to Financial Statements

420

Exelon Corporate

Balance Sheets


	December 31,
(In millions)	2009			2008
Current liabilities
Notes payable	$	—		$	56
Long-term debt due within one year		400			—
Accrued expenses		14			15
Other		56			53

Total current liabilities		470			124

Long-term debt		1,308			2,215
Deferred credits and other liabilities
Regulatory liabilities		30			30
Pension obligations		5,959			6,215
Non-pension postretirement benefit obligations		954			1,174
Other		69			83

Total deferred credits and other liabilities		7,012			7,502

Total liabilities		8,790			9,841

Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 660 and 658 shares outstanding at December 31, 2009 and 2008, respectively).		8,923			8,816
Retained earnings		8,134			6,820
Treasury stock, at cost (35 and 35 shares held at December 31, 2009 and 2008, respectively)		(2,328	)		(2,338	)
Accumulated other comprehensive loss, net		(2,089	)		(2,251	)

Total shareholders’ equity		12,640			11,047

Total liabilities and shareholders’ equity	$	21,430		$	20,888

See Notes to Financial Statements

421

1. Basis of Presentation

Exelon Corporate is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.

Exelon Corporate owns 100% of all significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and PECO Energy Company (PECO), of which Exelon Corporate owns 100% of the common stock but none of PECO’s preferred securities.

2. Debt and Credit Agreements

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had commercial paper borrowings at December 31, 2009 and December 31, 2008 of $0 and $56 million, respectively.

Credit Agreements

As of December 31, 2009, Exelon Corporate had access to separate unsecured credit facilities with aggregate bank commitments of $957 million and available capacity under those commitments of $952 million. The agreements are effective through October 26, 2012. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon Corporate’s credit agreements.

Long-Term Debt

Long-term debt maturities at Exelon Corporate in the periods 2010 through 2014 and thereafter are as follows:


	Exelon
2010	$	400
2011		—
2012		—
2013		—
2014		—
Remaining years		1,300

Total Long-term Debt	$	1,700
Unamortized debt discount and premium, net		(2	)
Fair value hedge carrying value adjustment, net		10

Long-term Debt	$	1,708

3. Commitments and Contingencies

See Note 18 of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to the voluntary GHG emissions reductions, pension claim, savings plan claim, retiree healthcare benefits grievance and fund transfer restrictions.

422

4. Related-Party Transactions

The financial statements of Exelon Corporate include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008		2007
Operating and maintenance from affiliates
Business Services Company (a)	$	35		$	31	$	31
Interest income from affiliates, net
Business Services Company	$	—		$	2	$	1
Generation		—			—		1

Total interest income from affiliates, net	$	—		$	2	$	2

Earnings of affiliates
Exelon Energy Delivery Company, LLC	$	723		$	522	$	668
Exelon Ventures Company, LLC		2,113			2,282		2,133
Unicom Investment, Inc		1			13		5
Exelon Transmission Company, LLC		(2	)		—		—

Total earnings in affiliates	$	2,835		$	2,817	$	2,806

Charitable contributions to Exelon Foundation (b)	$	10		$	—	$	50
Cash contributions received from affiliates		2,841			2,397		3,208


	December 31,
	2009			2008
Accounts receivable from affiliates
URI	$	—		$	7
Generation		6			44
ComEd		1			1
PECO		1			1
Exelon Transmission Company, LLC.		3			—

Total receivables from affiliates (current)	$	11		$	53

Notes receivable from affiliate (current)
Business Services Company	$	15		$	46
Investments in affiliates
Business Services Company	$	237		$	202
Exelon Energy Delivery Company, LLC		9,438			8,907
Exelon Ventures Company, LLC		6,219			6,313
Unicom Investment, Inc.		419			418
Exelon Transmission Company, LLC		(2	)		—
VEBA		2			8

Total investments in affiliates	$	16,313		$	15,848

Payables to affiliate (current)
BSC		8			6

(a)	Exelon Corporate 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.

(b)

Exelon Foundation is a nonconsolidated not-for-profit Illinois corporation. The Exelon Foundation was established in the fourth quarter of 2007 to serve educational and environmental philanthropic purposes and does not serve a direct business or political purpose of Exelon. Exelon contributes services (i.e. accounting, administrative, legal).

423

EXELON CORPORATION AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


Column A	Column B		Column C					Column D			Column E
Description	Balance at Beginning of Year		Additions and adjustments					Deductions			Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions			Balance at End of Year
*For The Year Ended December 31, 2009*

Allowance for uncollectible accounts	$	238	$	150	$	38	^(a)	$	201	^(b)	$	225

Deferred tax valuation allowance		29		9		—			2			36

Reserve for obsolete materials		28		19		—			2			45

*For The Year Ended December 31, 2008*

Allowance for uncollectible accounts	$	130	$	247	$	31	^(a)	$	170	^(b)	$	238

Deferred tax valuation allowance		33		—		—			4			29

Reserve for obsolete materials		29		2		2			5			28

*For The Year Ended December 31, 2007*

Allowance for uncollectible accounts	$	91	$	132	$	17	^(a)	$	110	^(b)	$	130

Deferred tax valuation allowance		37		—		—			4			33

Reserve for obsolete materials		27		4		—			2			29

(a)	Primarily charges for late payments and non-service receivables.

(b)	Write-off of individual accounts receivable.

424

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


(2)		Generation

(i)		Financial Statements

		Consolidated Statements of Operations for the years 2009, 2008 and 2007

		Consolidated Statements of Cash Flows for the years 2009, 2008 and 2007

		Consolidated Balance Sheets as of December 31, 2009 and 2008

		Consolidated Statements of Changes in Member’s Equity for the years 2009, 2008 and 2007

		Consolidated Statements of Comprehensive Income for the years 2009, 2008 and 2007

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule

425

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


Column A	Column B		Column C					Column D		Column E
Description	Balance at Beginning of Year		Additions and adjustments					Deductions		Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions		Balance at End of Year
*For The Year Ended December 31, 2009*

Allowance for uncollectible accounts	$	30	$	2	$	—		$	1	$	31

Deferred tax valuation allowance		20		—		—			2		18

Reserve for obsolete materials		26		17		—			—		43

*For The Year Ended December 31, 2008*

Allowance for uncollectible accounts	$	17	$	17	$	(3	)	$	1	$	30

Deferred tax valuation allowance		32		—		—			12		20

Reserve for obsolete materials		26		—		—			—		26

*For The Year Ended December 31, 2007*

Allowance for uncollectible accounts	$	17	$	—	$	—		$	—	$	17

Deferred tax valuation allowance		33		—		(1	)		—		32

Reserve for obsolete materials		24		2		—			—		26

426

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


(3)		ComEd

(i)		Financial Statements

		Consolidated Statements of Operations for the years 2009, 2008 and 2007

		Consolidated Statements of Cash Flows for the years 2009, 2008 and 2007

		Consolidated Balance Sheets as of December 31, 2009 and 2008

		Consolidated Statements of Changes in Shareholders’ Equity for the years 2009, 2008 and 2007

		Consolidated Statements of Comprehensive Income for the years 2009, 2008 and 2007

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule

427

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


Column A	Column B		Column C					Column D			Column E
Description	Balance at Beginning of Year		Additions and adjustments					Deductions			Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions			Balance at End of Year
*For The Year Ended December 31, 2009*

Allowance for uncollectible accounts	$	57	$	85	$	27	^(a)	$	92	^(b)	$	77

Reserve for obsolete materials		1		2		—			2			1

*For The Year Ended December 31, 2008*

Allowance for uncollectible accounts	$	53	$	71	$	20	^(a)	$	87	^(b)	$	57

Reserve for obsolete materials		3		3		—			5			1

*For The Year Ended December 31, 2007*

Allowance for uncollectible accounts	$	20	$	58	$	16	^(a)	$	41	^(b)	$	53

Reserve for obsolete materials		3		2		—			2			3

(a)	Primarily charges for late payments and non-service receivables.

(b)	Write-off of individual accounts receivable.

428

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


(4)		PECO

(i)		Financial Statements

		Consolidated Statements of Operations for the years 2009, 2008 and 2007

		Consolidated Statements of Cash Flows for the years 2009, 2008 and 2007

		Consolidated Balance Sheets as of December 31, 2009 and 2008

		Consolidated Statements of Changes in Shareholders’ Equity for the years 2009, 2008 and 2007

		Consolidated Statements of Comprehensive Income for the years 2009, 2008 and 2007

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule

429

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


Column A	Column B		Column C						Column D			Column E
Description	Balance at Beginning of Year		Additions and adjustments						Deductions			Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses			Charged to Other Accounts			Deductions			Balance at End of Year
*For The Year Ended December 31, 2009*

Allowance for uncollectible accounts	$	151	$	63		$	11	^(a)	$	108	^(b)	$	117

Reserve for obsolete materials		1		—			—			—			1

*For The Year Ended December 31, 2008*

Allowance for uncollectible accounts	$	59	$	160		$	15	^(a)	$	83	^(b)	$	151

Reserve for obsolete materials		1		(1	)		1			—			1

*For The Year Ended December 31, 2007*

Allowance for uncollectible accounts	$	51	$	71		$	5	^(a)	$	68	^(b)	$	59

Reserve for obsolete materials		1		—			—			—			1

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

430

(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	Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).

3-2	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).

3-3	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).

3-4	Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).

3-5	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).

3-6	Commonwealth Edison Company Amended and Restated By-Laws, effective January 23, 2006 As Further Amended January 28, 2008. (File No. 001-16169, Form 10-Q for the quarter ended September 30, 2008, Exhibit 10-1).

3-7	Exelon Corporation Amended and Restated Bylaws, as amended September 23, 2008 (File 001-16169, Form 8-K dated September 25, 2008, Exhibit 3.1).

3-8	Amended and Restated Articles of Incorporation of Exelon Corporation, as amended May 8, 2007 (File No. 001-16169, Form 10-Q for the quarter ended September 30, 2008, Exhibit 3-1-2).

3-9	PECO Energy Company Amended Bylaws (File 000-16844, Form 8-K dated May 6, 2009, Exhibit 99.1)

4-1	First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (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)

	November 1, 1944	2-5472	B-1(i)

	December 1, 1946	2-6821	7-1(j)

431


	Dated as of	File Reference	Exhibit No.
	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)

	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

	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	0-6844, September 30, 2004 Form 10-Q	4-1-1

	September 15, 2006	000-16844, Form 8-K dated September 25, 2006	4.1

	March 1, 2007	000-16844, Form 8-K dated March 19, 2007	4.1

	February 15, 2008	0-16844, Form 8-K dated March 3, 2008	4.1

	February 15, 2008	0-16844, Form 8-K, dated March 5, 2008	4.1

	September 15, 2008	000-16844, Form 8-K dated October 2, 2008	4.1

	March 15, 2009	000-16844, Form 8-K dated March 26, 2009	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 Mellon Trust Company of Illinois, 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

432


Dated as of	File Reference	Exhibit No.

April 1,1967	2-60201, Form S-7	2-1

February 28, 1969	2-60201, Form S-7	2-1

May 29, 1970	2-60201, Form S-7	2-1

June 1, 1971	2-60201, Form S-7	2-1

April 1, 1972	2-60201, Form S-7	2-1

May 31, 1972	2-60201, Form S-7	2-1

June 15, 1973	2-60201, Form S-7	2-1

May 31, 1974	2-60201, Form S-7	2-1

June 13, 1975	2-60201, Form S-7	2-1

May 28, 1976	2-60201, Form S-7	2-1

June 3, 1977	2-60201, Form S-7	2-1

May 17, 1978	2-99665, Form S-3	4-3

August 31, 1978	2-99665, Form S-3	4-3

June 18, 1979	2-99665, Form S-3	4-3

June 20, 1980	2-99665, Form S-3	4-3

April 16, 1981	2-99665, Form S-3	4-3

April 30, 1982	2-99665, Form S-3	4-3

April 15, 1983	2-99665, Form S-3	4-3

April 13, 1984	2-99665, Form S-3	4-3

April 15, 1985	2-99665, Form S-3	4-3

April 15, 1986	33-6879, Form S-3	4-9

April 15, 1993	33-64028, Form S-3	4-13

June 15, 1993	1-1839, Form 8-K dated May 21, 1993	4-1

January 15, 1994	1-1839, 1993 Form 10-K	4-15

March 1, 2002	1-1839, 2001 Form 10-K	4-4-1

May 20, 2002	333-99363, Form S-3	4-1-1(A)

June 1, 2002	333-99363, Form S-3	4-1-1(B)

October 7, 2002	333-9715, Form S-4	4-1-3

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

433


	Dated as of	File Reference	Exhibit No.

	February 15, 2005	1-1839, Form 10-Q for the quarter ended March 31, 2005	4-3-1

	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

	March 1, 2007	1-1839, Form 8-K dated March 23, 2007	4.1

	August 30, 2007	1-1839, Form 8-K dated September 10, 2007	4.1

	December 20, 2007	1-1839, Form 8-K dated January 16, 2008	4.1

	March 10, 2008	1-1839, Form 8-K dated March 27, 2008	4.1

	April 23, 2008	001-01839, Form 8-K dated May 12, 2008	4.1

	June 12, 2008	001-01839, Form 8-K dated June 27, 2008	4.1

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., (U.S. Bank National Association, as current successor trustee) Trustee relating to Notes (File No. 33-20619, Form S-3, Exhibit 4-13).

4-4-1	Supplemental Indentures to aforementioned Indenture.

	Dated as of	File Reference	Exhibit No.
	July 14, 1989	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).

434


Exhibit No.		Description
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, June 30, 2003 Form 10-Q, 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, June 30, 2003 Form 10-Q, 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, June 30, 2003 Form 10-Q, 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, June 30, 2005 Form 10-Q, 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).

4-14		Indenture dated as of September 28, 2007 from Generation to U.S. Bank National Association, as trustee (File 333-85496, Form 8-K dated September 28, 2007, Exhibit 4.1).

4-15		Pollution Control Note dated as of February 15, 2008 from PECO to U.S. Bank National Association, as trustee (File 0-16844, Form 8-K dated March 5, 2008, Exhibit 4.2)

4-16		Form of 5.20% Senior Note due 2019. (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.1)

4-17		Form of 6.25% Senior Note due 2039. (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.2)

10-1		Power Purchase Agreement among Generation and PECO (File No. 333-85496, Form S-4, Exhibit 10.1).

10-2		Exelon Corporation Deferred Non-Employee Directors’ Deferred Stock Unit Plan (As Amended and Restated Effective January 1, 2009) (File No. 001-16169, 2008 Form 10-K, Exhibit 10.2).

10-3		Exelon Corporation Retirement Program (File No. 1-16169, 2001 Form 10-K, Exhibit 10-4).

10-4		Exelon Corporation Deferred Compensation Plan for Directors (as amended and restated Effective January 1, 2009) (File No. 001-16169, 2008 Form 10-K, Exhibit 10.4).

10-5		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).

10-6-1		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).

10-6-2		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).

435


Exhibit No.		Description
10-6-3		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).

10-7		Exelon Corporation Employee Savings Plan (File No. 1-16169, 2004 Form 10-K, Exhibit 10-13).

10-8		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).

10-9		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).

10-9-1		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).

10-9-2		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).

10-9-3		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).

10-10		Intangible Transition Property Sale Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000, between PECO Energy Transition Trust and PECO Energy Company. (File No. 1-01401, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 10.1).

10-10-1		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, Exhibit 10.2).

10-11		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).

10-11-1		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, Exhibit 10.4).

10-12		Exelon Corporation Cash Balance Pension Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-14).

10-13		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. (File No. 333-31646, From S-3, Exhibit 10.3).

10-14		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, From S-3, Exhibit 10.4).

10-15		Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).

436


Exhibit No.		Description
10-16		Amendment Number One to the Unicom Corporation Deferred Compensation Unit Plan, as amended January 1, 2008 (File No. 001-16169, 2008 Form 10-K, Exhibit 10.16).

10-17		Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12).

10-18		Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-13).

10-19		Exelon Corporation Supplemental Management Retirement Plan (As Amended and Restated Effective January 1, 2009) (File No. 001-16169, 2008 Form 10-K, Exhibit 10.19).

10-20		PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009) (File No. 000-16844, 2008 Form 10-K, Exhibit 10.20).

10-21		Exelon Corporation Annual Incentive Plan for Senior Executives effective January 1, 2004 (As Amended and Restated Effective January 1, 2009).

10-22		Form of change in control employment agreement for senior executives effective January 1, 2009 (File No. 001-16169. 2008 Form 10-K, Exhibit 10.23).

10-23		Form of change in control employment agreement (amended and restated as of January 1, 2009) (File No. 001-16169, 2008 From 10-K, Exhibit 10.24).

10-24		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).

10-25		Exelon Corporation 2006 Long-Term Incentive Plan (Registration Statement No. 333-122704, Form S-4, Joint Proxy Statement-Prospectus pursuant to Rule 424(b)(3) filed June 3, 2005, Annex H).

10-26		Form of Stock Option Grant Instrument under the Exelon Corporation 2006 Long-Term Incentive Plan (File No. 1-16169, Form 8-K filed January 27, 2006, Exhibit 99.2).

10-27		Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries (Registration Statement No. 333-122704, Form S-4, Joint Proxy Statement-Prospectus pursuant to Rule 424(b)(3) filed June 3, 2005, Annex I).

10-28		Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2009) (File No. 001-16169, 2008 Form 10-K, Exhibit 10.29).

10-29		Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2009) (File No, 001-16169, 2008 Form 10-K, Exhibit 10.30).

10-30		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).

10-31		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).

10-32		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).

10-33		Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 (File No. 1-16169, 2006 Form 10-K, Exhibit 10-52).

437


Exhibit No.		Description
10-34		First Amendment to Exelon Corporation Executive Death Benefits Plan, effective January 1, 2006 (File No. 1-16169, 2006 Form 10-K, Exhibit 10-53).

10-35		Amendment Number One to the Exelon Corporation 2006 Long-Term Incentive Plan, effective December 4, 2006 (File No. 1-16169, 2006 Form 10-K, Exhibit 10-54).

10-36		Amendment Number Two to the Exelon Corporation 2006 Long-Term Incentive Plan (As Amended and Restated Effective January 28, 2002), effective December 4, 2006 (File No. 1-16169, 2006 Form 10-K, Exhibit 10-55).

10-37		Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-K, Exhibit 10-56).

10-38		Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-K, Exhibit 10-57).

10-39		Commonwealth Edison Company Long-Term Incentive Plan, effective January 1, 2007 (File No. 1-16169, March 31, 2007 Form 10-Q, Exhibit 10-1).

10-40		Amendment Number One to the Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, June 30, 2007 Form 10-Q, Exhibit 10-3).

10-41		Credit Agreement dated as of October 3, 2007 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 October 3, 2007, Exhibit 99.1).

10-42		Restricted stock unit award agreement (File 1-16169, Form 8-K dated August 31, 2007, Exhibit 99.1).

10-43		Settlement Agreement by and between the City of Chicago and Commonwealth Edison Company effective December 21, 2007. (File No. 001-1839, 2007 Form 10-K, Exhibit 10-56).

10-44		Amendment No. 1 to $1,000,000,000 Credit Agreement dated as of October 3, 2007 among Commonwealth Edison Company, as Borrower, Various Financial Institutions, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File 001-01839, Form 8-K dated May 9, 2008, Exhibit 10.4).

10-45		Amended and Restated Trade Receivables Purchase and Sale Agreement among PECO, Victory Receivables Corporation and The Bank of Tokyo-Mitsubishi UFJ, Ltd. dated as of December 20, 1988, as Amended and Restated as of November 14, 1995, as of January 1, 1999, as of November 14, 2000, as of November 14, 2005 and as Further Amended and Restated as of September 19, 2008 (File 000-16844, Form 8-K dated September 22, 2008, Exhibit 10.1).

10-46		Amendment No. 1 to $1,000,000,000 Credit Agreement dated as of October 26, 2006 among Exelon Corporation, as Borrower, Various Financial Institutions, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File 001-16169, Form 8-K dated October 21, 2008, Exhibit 99.1)

10-47		Amendment No. 1 to $5,000,000,000 Credit Agreement dated as of October 26, 2006 among Exelon Generation Company, as Borrower, Various Financial Institutions, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File 333-85496, Form 8-K dated October 21, 2008, Exhibit 99.2)

10-48		Amendment No. 2 to $1,000,000,000 Credit Agreement dated as of October 3, 2007 among Commonwealth Edison Company, as Borrower, Various Financial Institutions, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File 001-01839, Form 8-K dated October 21, 2008, Exhibit 99.3)

438


Exhibit No.		Description
10-49		Amendment No. 1 to $600,000,000 Credit Agreement dated as of October 26, 2006 among PECO Energy Company, as Borrower, Various Financial Institutions, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File 000-16844, Form 8-K dated October 21, 2008, Exhibit 99.4)

10-50		Amendment No. 1 to Amended and Restated Trade Receivables Purchase and Sale Agreement among PECO, Victory Receivables Corporation and The Bank of Tokyo-Mitsubishi UFJ, Ltd. (File 000-16844, Form 8-K dated September 17, 2009, Exhibit 10.1)

10-51		Third Amended and Restated Employment Agreement with John W. Rowe (File 1-16169, Form 8-K dated October 29, 2009, Exhibit 99.1)

14		Exelon Code of Conduct (File No. 1-16169, 2006 Form 10-K, Exhibit 14).

		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		Exelon Generation Company, LLC

23-3		Commonwealth Edison Company

23-4		PECO Energy Company

		Power of Attorney (Exelon Corporation)

24-1		John A. Canning, Jr.

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		Paul L. Joskow

24-9		Richard W. Mies

24-10		John M. Palms, Ph.D.

24-11		William C. Richardson

24-12		Thomas J. Ridge

24-13		John W. Rogers, Jr.

24-14		Stephen D. Steinour

24-15		Donald Thompson

439


Exhibit No.		Description
		Power of Attorney (Commonwealth Edison Company)

24-16		James W. Compton

24-17		Peter V. Fazio, Jr.

24-18		Sue L. Gin

24-19		Edgar D. Jannotta

24-20		Edward J. Mooney

24-21		Michael Moskow

24-22		John W. Rogers, Jr.

24-23		Jesse H. Ruiz

24-24		Richard L. Thomas

		Power of Attorney (PECO Energy Company)

24-25		M. Walter D’Alessio

24-26		Nelson A. Diaz

24-27		Rosemarie B. Greco

24-28		Thomas J. Ridge

24-29		Ronald Rubin

		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, 2009 filed by the following officers for the following registrants:

31-1		Filed by John W. Rowe for Exelon Corporation

31-2		Filed by Matthew F. Hilzinger for Exelon Corporation

31-3		Filed by John W. Rowe for Exelon Generation Company, LLC

31-4		Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC

31-5		Filed by Frank M. Clark for Commonwealth Edison Company

31-6		Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

31-7		Filed by Denis P. O’Brien for PECO Energy Company

31-8		Filed by Phillip S. Barnett 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, 2009 filed by the following officers for the following registrants:

32-1		Filed by John W. Rowe for Exelon Corporation

440


Exhibit No.		Description
32-2		Filed by Matthew F. Hilzinger for Exelon Corporation

32-3		Filed by John W. Rowe for Exelon Generation Company, LLC

32-4		Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC

32-5		Filed by Frank M. Clark for Commonwealth Edison Company

32-6		Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

32-7		Filed by Denis P. O’Brien for PECO Energy Company

32-8		Filed by Phillip S. Barnett for PECO Energy Company

101.INS	**	XBRL Instance

101.SCH	**	XBRL Taxonomy Extension Schema

101.CAL	**	XBRL Taxonomy Extension Calculation

101.DEF	**	XBRL Taxonomy Extension Definition

101.LAB	**	XBRL Taxonomy Extension Labels

101.PRE	**	XBRL Taxonomy Extension Presentation

*	Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.

**	XBRL information will be considered to be furnished, not filed for the first two years of a company’s submission of XBRL information.

441

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 5th day of February, 2010.


EXELON CORPORATION

By:		/s/ JOHN W. ROWE
Name:		John W. Rowe
Title:		Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 5th day of February, 2010.


Signature		Title

/s/ JOHN W. ROWE John W. Rowe		Chairman and Chief Executive Officer (Principal Executive Officer)

/S/ MATTHEW F. HILZINGER Matthew F. Hilzinger		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ DUANE M. DESPARTE Duane M. DesParte		Vice President and Corporate Controller (Principal Accounting Officer)

This annual report has also been signed below by William A. Von Hoene, Jr., Attorney-in-Fact, on behalf of the following Directors on the date indicated:


John A. Canning, Jr.		Richard W. Mies
M. Walter D’Alessio		John M. Palms, PhD.
Nicholas DeBenedictis		William C. Richardson
Bruce DeMars		Thomas J. Ridge
Nelson A. Diaz		John W. Rogers, Jr.
Sue L. Gin		Stephen D. Steinour
Rosemarie B. Greco		Donald Thompson
Paul L. Joskow



By:	/s/ WILLIAM A. VON HOENE, JR.	February 5, 2010
Name:	William A. Von Hoene, Jr.

442

SIGNATURES


EXELON GENERATION COMPANY, LLC

By:		/s/ JOHN W. ROWE
Name:		John W. Rowe
Title:		Chairman


Signature		Title

/s/ JOHN W. ROWE John W. Rowe		Chairman (Principal Executive Officer)

/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger		(Principal Financial Officer)

/s/ MATTHEW R. GALVANONI Matthew R. Galvanoni		(Principal Accounting Officer)

443

SIGNATURES


COMMONWEALTH EDISON COMPANY

By:		/s/ FRANK M. CLARK
Name:		Frank M. Clark
Title:		Chairman and Chief Executive Officer


Signature		Title

/s/ FRANK M. CLARK Frank M. Clark		Chairman and Chief Executive Officer (Principal Executive Officer)

/s/ ANNE R. PRAMAGGIORE Anne R. Pramaggiore		President and Chief Operating Officer

/s/ JOSEPH R. TRPIK, JR. Joseph R. Trpik, Jr.		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ KEVIN J. WADEN Kevin J. Waden		Vice President and Controller (Principal Accounting Officer)

/s/ JOHN W. ROWE John W. Rowe		Director

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:


James W. Compton		Michael Moskow
Peter V. Fazio, Jr.		John W. Rogers, Jr.
Sue L. Gin		Jesse H. Ruiz
Edgar D. Jannotta		Richard L. Thomas
Edward J. Mooney


By:	/s/ FRANK M. CLARK	February 5, 2010
Name:	Frank M. Clark

444

SIGNATURES


PECO ENERGY COMPANY

By:		/s/ DENIS P. O’BRIEN
Name:		Denis P. O’Brien
Title:		Chief Executive Officer and President


Signature		Title

/s/ DENIS P. O’BRIEN Denis P. O’Brien		Chief Executive Officer and President (Principal Executive Officer)

/s/ PHILLIP S. BARNETT Phillip S. Barnett		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ JORGE A. ACEVEDO Jorge A. Acevedo		Vice President and Controller (Principal Accounting Officer)

/s/ JOHN W. ROWE John W. Rowe		Chairman and Director

This annual report has also been signed below by Paul R. Bonney, Attorney-in-Fact, on behalf of the following Directors on the date indicated:


M. Walter D’Alessio		Thomas J. Ridge
Nelson A. Diaz		Ronald Rubin
Rosemarie B. Greco


By:	/s/ PAUL R. BONNEY	February 5, 2010
Name:	Paul R. Bonney

445