Edgar Filing: EXELON GENERATION CO LLC

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, 2012

¨	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
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000	52-0280210

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
Series A Junior Subordinated Debentures		New York
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
BALTIMORE GAS AND ELECTRIC COMPANY:
6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and unconditionally guaranteed, by Baltimore Gas and Electric 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 ¨
Baltimore Gas and Electric 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
Baltimore Gas and Electric 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. ¨

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
Baltimore Gas and Electric 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
Baltimore Gas and Electric 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, 2012 was as follows:


Exelon Corporation Common Stock, without par value		$ 32,084,086,343
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
Baltimore Gas and Electric Company, without par value		None

The number of shares outstanding of each registrant’s common stock as of January 31, 2013 was as follows:


Exelon Corporation Common Stock, without par value		855,019,272
Exelon Generation Company, LLC		not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,761
PECO Energy Company Common Stock, without par value		170,478,507
Baltimore Gas and Electric Company, without par value		1,000

Documents Incorporated by Reference

Portions of the Exelon Proxy Statement for the 2013 Annual Meeting of

Shareholders and the Commonwealth Edison Company and PECO Energy Company 2013 information statements are incorporated by reference in Part III.

Exelon Generation Company, LLC and Baltimore Gas and Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the reduced disclosure format.

TABLE OF CONTENTS


		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS			1
FILING FORMAT			5
FORWARD-LOOKING STATEMENTS			5
WHERE TO FIND MORE INFORMATION			5

PART I
ITEM 1.	BUSINESS		6
	General		6
	Exelon Generation Company, LLC		7
	Commonwealth Edison Company		19
	PECO Energy Company		21
	Baltimore Gas and Electric Company		24
	Employees		28
	Environmental Regulation		29
	Executive Officers of the Registrants		34
ITEM 1A.	RISK FACTORS		39
ITEM 1B.	UNRESOLVED STAFF COMMENTS		62
ITEM 2.	PROPERTIES		63
	Exelon Generation Company, LLC		63
	Commonwealth Edison Company		66
	PECO Energy Company		66
	Baltimore Gas and Electric Company		67
ITEM 3.	LEGAL PROCEEDINGS		68
	Exelon Corporation		68
	Exelon Generation Company, LLC		68
	Commonwealth Edison Company		68
	PECO Energy Company		68
	Baltimore Gas and Electric Company		68
ITEM 4.	MINE SAFETY DISCLOSURES		68

PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		69
ITEM 6.	SELECTED FINANCIAL DATA		73
	Exelon Corporation		73
	Exelon Generation Company, LLC		74
	Commonwealth Edison Company		74
	PECO Energy Company		75
	Baltimore Gas and Electric Company		76
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		77
	Exelon Corporation		77
	Executive Overview		77
	Critical Accounting Policies and Estimates		94
	Results of Operations		109
	Liquidity and Capital Resources		144
	Exelon Generation Company, LLC		173
	Commonwealth Edison Company		175
	PECO Energy Company		177
	Baltimore Gas and Electric Company		179


		Page No.
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		161
	Exelon Corporation		161
	Exelon Generation Company, LLC		174
	Commonwealth Edison Company		176
	PECO Energy Company		178
	Baltimore Gas and Electric Company		180
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		181
	Exelon Corporation		191
	Exelon Generation Company, LLC		196
	Commonwealth Edison Company		201
	PECO Energy Company		206
	Baltimore Gas and Electric Company		211
	Combined Notes to Consolidated Financial Statements		216
	1. Significant Accounting Policies		216
	2. Variable Interest Entities		231
	3. Regulatory Matters		236
	4. Merger and Acquisitions		261
	5. Accounts Receivable		272
	6. Property, Plant and Equipment		273
	7. Jointly Owned Electric Utility Plant		276
	8. Intangible Assets		277
	9. Fair Value of Financial Assets and Liabilities		281
	10. Derivative Financial Instruments		304
	11. Debt and Credit Agreements		320
	12. Income Taxes		331
	13. Asset Retirement Obligations		341
	14. Retirement Benefits		349
	15. Corporate Restructuring and Plant Retirements		366
	16. Preferred and Preference Securities		367
	17. Common Stock		369
	18. Earnings Per Share and Equity		376
	19. Commitments and Contingencies		377
	20. Supplemental Financial Information		401
	21. Segment Information		411
	22. Related Party Transactions		416
	23. Quarterly Data		424
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		427
ITEM 9A.	CONTROLS AND PROCEDURES		427
	Exelon Corporation		427
	Exelon Generation Company, LLC		427
	Commonwealth Edison Company		427
	PECO Energy Company		427
	Baltimore Gas and Electric Company		427
ITEM 9B.	OTHER INFORMATION		428
	Exelon Corporation		428
	Exelon Generation Company, LLC		428
	Commonwealth Edison Company		428
	PECO Energy Company		428
	Baltimore Gas and Electric Company		428


		Page No.
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		429
ITEM 11.	EXECUTIVE COMPENSATION		430
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		431
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		432
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		433

PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		434

SIGNATURES			467
	Exelon Corporation		467
	Exelon Generation Company, LLC		468
	Commonwealth Edison Company		469
	PECO Energy Company		470
	Baltimore Gas and Electric Company		471

CERTIFICATION EXHIBITS			472

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
BGE		Baltimore Gas and Electric Company
BSC		Exelon Business Services Company, LLC
Exelon Corporate		Exelon’s holding company
CENG		Constellation Energy Nuclear Group, LLC
Constellation		Constellation Energy Group, Inc.
Exelon Transmission Company		Exelon Transmission Company, LLC
Exelon Wind		Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
Ventures		Exelon Ventures Company, LLC
AmerGen		AmerGen Energy Company, LLC
BondCo		RSB BondCo LLC
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, PECO and BGE, collectively

Other Terms and Abbreviations
1998 restructuring settlement		PECO’s 1998 settlement of its restructuring case mandated by the Competition Act
Act 11		Pennsylvania Act 11 of 2012
Act 129		Pennsylvania Act 129 of 2008
AEC		Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AEPS		Pennsylvania Alternative Energy Portfolio Standards
AEPS Act		Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended
AESO		Alberta Electric Systems Operator
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ARP		Title IV Acid Rain Program
ARRA of 2009		American Recovery and Reinvestment Act of 2009
Block contracts		Forward Purchase Energy Block Contracts
CAIR		Clean Air Interstate Rule
CAISO		California ISO
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CFL		Compact Fluorescent Light
Clean Air Act		Clean Air Act of 1963, as amended
Clean Water Act		Federal Water Pollution Control Amendments of 1972, as amended


Other Terms and Abbreviations
Competition Act		Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996
CPI		Consumer Price Index
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CTC		Competitive Transition Charge
DOE		United States Department of Energy
DOJ		United States Department of Justice
DSP		Default Service Provider
DSP Program		Default Service Provider Program
EDF		Electricite de France SA
EE&C		Energy Efficiency and Conservation/Demand Response
EGS		Electric Generation Supplier
EIMA		Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA		United States Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act of 1974, as amended
EROA		Expected Rate of Return on Assets
ESPP		Employee Stock Purchase Plan
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
FTC		Federal Trade Commission
GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
GRT		Gross Receipts Tax
GSA		Generation Supply Adjustment
GWh		Gigawatt hour
HAP		Hazardous air pollutants
Health Care Reform Acts		Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010
IBEW		International Brotherhood of Electrical Workers
ICC		Illinois Commerce Commission
ICE		Intercontinental Exchange
Illinois Act		Illinois Electric Service Customer Choice and Rate Relief Law of 1997
Illinois EPA		Illinois Environmental Protection Agency
Illinois Settlement Legislation		Legislation enacted in 2007 affecting electric utilities in Illinois
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
ISO		Independent System Operator
ISO-NE		ISO New England Inc.
ISO-NY		ISO New York
kV		Kilovolt
kW		Kilowatt
kWh		Kilowatt-hour
LIBOR		London Interbank Offered Rate
LILO		Lease-In, Lease-Out
LLRW		Low-Level Radioactive Waste


Other Terms and Abbreviations
LTIP		Long-Term Incentive Plan
MATS		U.S. EPA Mercury and Air Toxics Rule
MBR		Market Based Rates Incentive
MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MGP		Manufactured Gas Plant
MISO		Midwest Independent Transmission System Operator, Inc.
mmcf		Million Cubic Feet
Moody’s		Moody’s Investor Service
MRV		Market-Related Value
MW		Megawatt
MWh		Megawatt hour
NAAQS		National Ambient Air Quality Standards
n.m.		not meaningful
NAV		Net Asset Value
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
NGS		Natural Gas Supplier
NJDEP		New Jersey Department of Environmental Protection
Non-Regulatory Agreements Units		Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOV		Notice of Violation
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NWPA		Nuclear Waste Policy Act of 1982
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income
OIESO		Ontario Independent Electricity System Operator
OPEB		Other Postretirement Employee Benefits
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
POR		Purchase of Receivables
PPA		Power Purchase Agreement
Price-Anderson Act		Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP		Potentially Responsible Parties
PSEG		Public Service Enterprise Group Incorporated
PURTA		Pennsylvania Public Realty Tax Act
PV		Photovoltaic
RCRA		Resource Conservation and Recovery Act of 1976, as amended
REC		Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units		Nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RES		Retail Electric Suppliers
RFP		Request for Proposal


Other Terms and Abbreviations
Rider		Reconcilable Surcharge Recovery Mechanism
RGGI		Regional Greenhouse Gas Initiative
RMC		Risk Management Committee
RPM		PJM Reliability Pricing Model
RPS		Renewable Energy Portfolio Standards
RTEP		Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
Senate Bill 1		Maryland Senate Bill 1
SERC		SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SERP		Supplemental Employee Retirement Plan
SFC		Supplier Forward Contract
SGIG		Smart Grid Investment Grant
SGIP		Smart Grid Initiative Program
SILO		Sale-In, Lease-Out
SMP		Smart Meter Program
SMPIP		Smart Meter Procurement and Installation Plan
SNF		Spent Nuclear Fuel
SOS		Standard Offer Service
SPP		Southwest Power Pool
Tax Relief Act of 2010		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
TEG		Termoelectrica del Golfo
TEP		Termoelectrica Penoles
Upstream		Natural gas exploration and production activities
VIE		Variable Interest Entity
WECC		Western Electric Coordinating Council

FILING FORMAT

This combined Annual Report on Form 10-K is being filed separately by the Registrants. Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a Registrant include those factors discussed herein, including those factors with respect to such Registrant discussed in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, (c) ITEM 8. Financial Statements and Supplementary Data: Note 19 and (d) other factors discussed herein and in other 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 the Registrants file 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 website maintained by the SEC at www.sec.gov and the Registrants’ websites at www.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.

PART I

ITEM 1.

BUSINESS

General

Corporate Structure and Business and Other Information

Exelon, incorporated in Pennsylvania in February 1999, is a utility services holding company engaged, through its principal subsidiary, Generation, in the energy generation business, and through its principal subsidiaries ComEd, PECO and BGE, in the energy delivery businesses discussed below. 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 integrated business consists of its owned and contracted electric generating facilities and investments in generation ventures that are marketed through its leading customer-facing activities. These customer-facing activities include, wholesale energy marketing operations and its competitive retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions.

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 gas 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.

BGE

BGE’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 central Maryland,

including the City of Baltimore, as well as the purchase and regulated retail sale of natural gas and the provision of gas distribution services to retail customers in central Maryland, including the City of Baltimore.

BGE was incorporated in Maryland in 1906. BGE’s principal executive offices are located at 110 West Fayette Street, Baltimore, Maryland 21201, and its telephone number is 410-234-5000.

Operating Segments

See Note 21 of the Combined Notes to Consolidated Financial Statements for additional information on Exelon’s operating segments.

Merger with Constellation Energy Group, Inc.

On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation Energy Group, Inc. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’s interest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon’s interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including those with generation and customer supply operations that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information on the Constellation transaction.

Generation

Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and contracted MW. Generation creates incremental strategic value by operating as an integrated business and matching its large generation fleet with a leading customer-facing platform. Generation’s presence in well-developed energy markets, its integrated hedging strategy mitigating short-term market volatility, and its low-cost nuclear generating fleet operating consistently at high capacity factors, position it well to succeed in competitive energy markets.

Generation’s customer-facing business, now referred to as Constellation, utilizes Generation’s energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in spot markets. Generation also sells other energy-related products and other services to meet its customers’ requirements. Generation is dependent upon continued deregulation of retail electric and gas markets and its ability to generate and obtain supplies of electricity and gas at competitive prices in the market.

Generation is a public utility under the Federal Power Act, and is subject to FERC’s 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. FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of utilities (including Generation, which is a public utility as FERC defines that term) and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other 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. Additionally, ERCOT is not subject to regulation by FERC but performs a similar function in Texas. Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC and Federal and state environmental protection agencies. Additionally, Generation is subject to mandatory reliability standards promulgated by the NERC, with the approval of FERC.

RTOs exist in a number of regions to provide transmission service across multiple transmission systems. CAISO, PJM, MISO, ISO-NE, ISO-NY and SPP, have been approved by FERC as RTOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and NYMEX and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems.

Significant Acquisitions

Antelope Valley Solar Ranch One. On September 30, 2011, Generation acquired Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar photovoltaic (PV) project under development in northern Los Angeles County, California, from First Solar, which developed and will build, operate, and maintain the project. The first block began operations in December 2012, with three additional blocks coming online in February 2013 and an expectation of full commercial operation by the end of the third quarter of 2013. When fully operational, Antelope Valley will be one of the largest PV solar projects in the world, with approximately 3.8 million solar panels generating enough clean, renewable electricity to power the equivalent of 75,000 average homes per year. The project has a 25-year PPA, approved by the California Public Utilities Commission, with Pacific Gas & Electric Company for the full output of the plant. Exelon expects to invest up to $701 million in equity in the project through 2013. The DOE’s Loan Programs Office issued a loan guarantee of up to $646 million to support project financing for Antelope Valley. Exelon expects the total investment of up to $1.3 billion to be accretive to earnings and cash flows beginning in 2013. Once constructed and operating, the project is expected to have stable earnings and cash flow profiles due to the PPA.

Wolf Hollow Generating Station. On August 24, 2011, Generation completed the acquisition of all of the equity interests of Wolf Hollow, LLC (Wolf Hollow), a combined-cycle natural gas-fired power plant in north Texas, for a purchase price of $311 million which increased Generation’s owned capacity within the ERCOT power market by 720 MWs.

Exelon Wind. In 2010, Generation acquired 735 MWs of installed, operating wind capacity located in eight states for approximately $893 million in cash. In addition, Generation acquired development stage projects which became fully operational in 2012.

See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information on the above acquisitions.

Significant Dispositions

Maryland Clean Coal Stations. Associated with certain of the regulatory approvals required for the merger, Exelon and Constellation agreed to enter into contracts to sell three Constellation generating stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland within 150 days (subsequently extended 30 days by the DOJ)

following the merger completion. In accordance with that agreement, on November 30, 2012, a subsidiary of Generation sold these three Maryland generating stations and associated assets to Raven Power Holdings LLC, a subsidiary of Riverstone Holdings LLC for estimated net proceeds from the sale of approximately $371 million, which resulted in a pre-tax loss of $272 million. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

Generating Resources

At December 31, 2012, the generating resources of Generation consisted of the following:


Type of Capacity	MW
Owned generation assets^(a)
Nuclear		17,202
Fossil		12,050
Renewable (including Hydroelectric) ^(b)		3,516

Owned generation assets		32,768
Long-term contracts ^(c)		9,296
Investment in CENG ^(d)		1,963

Total generating resources		44,027

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

(b)	Includes equity method investment in certain generating facilities.

(c)	Excludes contracts with CENG. See Long-Term Contracts table in this section for additional information.

(d)	Generation owns a 50.01% interest in CENG, a joint venture with EDF. See ITEM 2. PROPERTIES—Generation and Note 22—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.

Generation has six reportable segments, the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions, representing the different geographical areas in which Generation’s customer-facing activities are conducted and where Generation’s generating resources are located. Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina (approximately 32% of capacity). Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee; and the entire United States footprint of MISO, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, and the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM; and parts of Montana, Missouri and Kentucky (approximately 34% of capacity). New England represents the operations within the ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont (approximately 8% of capacity). New York represents the operations within ISO-NY, which covers the state of New York in its entirety (approximately 3% of capacity). ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas (approximately 11% of capacity). Other Regions is an aggregate of regions not considered individually significant (approximately 12% of capacity).

Nuclear Facilities

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with an aggregate of 17,202 MW of capacity. Generation wholly owns all of its nuclear generating stations, except for Quad Cities Generating Station (75% ownership), Peach Bottom Generating Station (50% ownership) and Salem Generating Station (Salem) (42.59% ownership). Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2012 and 2011, electric supply (in GWh) generated from

the nuclear generating facilities was 53% and 82%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric and renewable generation and electric supply purchased for resale. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of Generation’s electric supply sources.

Constellation Energy Nuclear Group, Inc.

Generation also owns a 50.01% interest in CENG, a joint venture with EDF. CENG is governed by a board of ten directors, five of which are appointed by Generation and five by EDF. CENG owns and operates a total of five nuclear generating facilities on three sites, Calvert Cliffs, Ginna and Nine Mile Point. CENG’s ownership share in the total capacity of these units is 3,925 MW. See ITEM 2. PROPERTIES for additional information on these sites.

Generation has a unit contingent PPA with CENG under which it purchases 85 to 90% of the output of CENG’s nuclear generating facilities that is not sold to third parties under the pre-existing PPAs through 2014. Beginning on January 1, 2015, and continuing to the end of the lives of the respective nuclear facilities, Generation will purchase 50.01% and EDF will purchase 49.99% of the output of the CENG’s nuclear facilities. All commitments to purchase subsequent to December 31, 2014 are at market prices. See Note 22—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information regarding CENG.

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 operations from its nuclear plants have historically had minimal environmental impact and the plants have a safe operating history.

During 2012 and 2011, the nuclear generating facilities operated by Generation achieved capacity factors of 92.7% and 93.3%, respectively. Generation 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 wholesale and retail marketing and 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. 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. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results, and communicates its assessment on a semi-annual basis. As of December 31, 2012, the NRC categorized each unit operated by Generation in the Licensee Response Column, which is the highest of five performance bands. 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 operating 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.

On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. For additional information on the NRC actions related to the Japan Earthquake and Tsunami and the industry’s response, see ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Executive Overview.

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 Three Mile Island Unit 1. Additionally, PSEG has 40-year operating licenses from the NRC and on June 30, 2011, received 20-year operating license renewals for Salem Units 1 and 2. On December 8, 2010, in connection with an Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:


Station	Unit		In-Service Date^(a)		Current License Expiration
Braidwood		1		1988		2026
		2		1988		2027
Byron		1		1985		2024
		2		1987		2026
Clinton		1		1987		2026
Dresden^(b)		2		1970		2029
		3		1971		2031
LaSalle		1		1984		2022
		2		1984		2023
Limerick ^(c)		1		1986		2024
		2		1990		2029
Oyster Creek^(b)(d)		1		1969		2029
Peach Bottom^(b)		2		1974		2033
		3		1974		2034
Quad Cities^(b)		1		1973		2032
		2		1973		2032
Salem^(b)		1		1977		2036
		2		1981		2040
Three Mile Island^(b)		1		1974		2034

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

(b)	Stations for which the NRC has issued a renewed operating licenses.

(c)	On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years.

(d)	In December, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019.

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 except for Oyster Creek.

In August 2012, Generation entered into an operating services agreement with the Omaha Public Power District (OPPD) to provide operational and managerial support services for the Fort Calhoun Station and a licensing agreement for use of the Exelon Nuclear Management Model. The terms for both agreements are 20 years. OPPD will continue to own the plant and remain the NRC licensee.

Nuclear Uprate Program. Generation is engaged in individual projects as part of a planned power uprate program across its nuclear fleet. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and application of expertise gained from a half-century of nuclear power operations. The uprates are being undertaken pursuant to an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the plan in light of changing market conditions. Decisions to implement uprates at particular nuclear plants, the amount of expenditures to implement the plan, and the actual MWs of additional capacity attributable to the uprate program will be determined on a project-by-project basis in accordance with Exelon’s normal project evaluation standards and ultimately will depend on market conditions, economic and policy considerations, and other factors.

Based on recent reviews, the nuclear uprate implementation plan was adjusted during 2012, primarily as a result of market conditions, including low natural gas prices and the continued sluggish economy, resulting in the deferral or cancellation of certain projects. In addition, the ability to implement several projects requires the successful resolution of various technical matters. The resolution of these matters may further affect the timing and amount of the power increases associated with the power uprate initiative. Following these reviews, any projects that may be undertaken are expected to be completed by the end of 2021, and may result in between 1,125 and 1,200 MWs of additional capacity at an overnight cost of approximately $3.4 billion in 2013 dollars. Overnight costs do not include financing costs or cost escalation.

Approximately 75% of the planned uprate MWs projects are either complete and in service or in the installation or design and engineering phases across seven nuclear stations including Limerick and Peach Bottom in Pennsylvania and Byron, Braidwood, Dresden, LaSalle and Quad Cities in Illinois. The remaining 25% of uprate MWs, if and when completed, would come from an extended power uprate project at Limerick currently scheduled to begin in 2017. From the program announcement in 2008 through December 31, 2012, Generation has placed in service 310 MWs of nuclear generation through the uprate program at a cost of approximately $810 million, which has been capitalized to property, plant and equipment on Exelon’s and Generation’s consolidated balance sheets. At December 31, 2012, an additional approximate $310 million has been capitalized to construction work in progress (CWIP) within property, plant and equipment on Exelon’s and Generation’s consolidated balance sheets, of which approximately $200 million (202 MWs) relates to projects currently in the installation phase. The remaining $110 million (346 MWs) in CWIP relates to projects currently in the design and engineering phase that continue to be evaluated in accordance with Exelon’s normal project evaluation standards. The completion of those projects in the design and engineering phase will ultimately depend on market conditions, economic and policy considerations, and other factors. As of December 31, 2012, Generation believes it is more likely than not that all projects in CWIP will ultimately be placed in service. If a project in the design and engineering phase is expected to not be completed as planned, previously capitalized costs would be reversed through earnings as a charge to operating and maintenance expense.

New Nuclear Site Development. On August 28, 2012, Exelon halted efforts to gain initial federal regulatory approvals for new nuclear construction in Victoria County, Texas and notified the Nuclear Regulatory Commission that it has withdrawn its related Early Site Permit application. The action is in response to low natural gas prices and economic and market conditions that have made construction

of new merchant nuclear power plants in competitive markets uneconomical now and for the foreseeable future. The withdrawal of the license application brings an end to all project activity.

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 has developed dry cask storage facilities to support operations.

As of December 31, 2012, Generation had approximately 58,100 SNF assemblies (13,900 tons) stored on site in SNF pools or dry cask storage (this includes SNF assemblies at Zion Station, for which Generation retains ownership even though the responsibility for decommissioning Zion Station has been assumed by another party; see Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning). All currently operating Generation-owned nuclear sites have on-site dry cask storage, except for Clinton and Three Mile Island. Clinton and Three Mile Island will lose full core reserve, which is when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core, in 2015 and 2023, respectively. Dry cask storage will be in operation at Clinton and Three Mile Island prior to the closing of their respective on-site storage pools. 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 periods, and through decommissioning.

For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 19 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.

Generation is currently utilizing on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its Class A LLRW, which represent 93% of LLRW generated at its stations, 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. Generation has received NRC approval for its Peach Bottom and LaSalle stations that will allow storage at these sites of LLRW from its remaining stations with limited capacity. Generation now has enough storage capacity to store all Class B and C LLRW for the life of all stations in Generation’s nuclear fleet. During 2012, Generation entered into a six year contract to ship Class B and Class C LLRW to Texas. The terms of the agreement will provide for disposal of all current Class B and Class C LLRW stored at the stations, as well as the waste generated during the term of the agreement. Generation 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 industry risk-sharing provisions. See “Nuclear Insurance” within Note 19 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 3, 9 and 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.

Dresden Unit 1 and Peach Bottom Unit 1 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. Generation’s estimated liability to decommission Dresden Unit 1 and Peach Bottom Unit 1 as of December 31, 2012 was $195 million and $121 million, respectively. As of December 31, 2012, NDT funds set aside to pay for these obligations were $390 million.

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

On September 1, 2010, Generation and EnergySolutions completed the transactions contemplated by the ASA. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities associated with Zion Station. Pursuant to the ASA, ZionSolutions can periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request reimbursement; specifically, if certain milestones as defined in the ASA are not met, all or a portion of requested reimbursements shall be deferred until such milestones are met. See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning and see Note 2 of the Combined Notes to Consolidated Financial Statements for a discussion of variable interest entity considerations related to ZionSolutions.

Fossil and Renewable Facilities (including Hydroelectric)

Generation has ownership interests in 15,566 MW of capacity in fossil and renewable generating facilities currently in service. Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) jointly-owned facilities that include Keystone, Conemaugh, and Wyman; (2) ownership interests through equity method investments in Colver, Malacha, Safe Harbor, and Sunnyside; and (3) certain wind project entities with minority interest owners. Generation’s fossil and renewable generating stations are all operated by Generation, with the exception of Colver, Conemaugh, Keystone, LaPorte, Malacha, Safe Harbor, Sunnyside and Wyman, which are operated

by third parties. In 2012 and 2011, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 12% and 7%, respectively, of Generation’s total electric supply. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. PROPERTIES—Generation.

Exelon Wind. During 2012, six development projects with a combined capacity of approximately 400 MWs began commercial operations. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Exelon Corporation, Executive Overview for additional information.

Licenses. Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid. On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Muddy Run Pumped Storage Project and the Conowingo Hydroelectric Project, respectively. The FERC review process is scheduled to be completed by August 31, 2014 and September 1, 2014, when the current Conowingo and Muddy Run licenses expire.

Insurance. Generation maintains business interruption insurance for its renewable projects, and delay in start-up insurance for its renewable projects currently under construction. 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 for these operations, 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 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 long-term contracts. The following tables summarize Generation’s long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by region, in effect as of December 31, 2012:


Region	Number of Agreements		Expiration Dates	Capacity (MW)
Mid-Atlantic ^(a)		13	2013 - 2032		973
Midwest		10	2013 - 2026		2,981
New England		6	2015 - 2020		637
New York ^(a)		1	2013		100
ERCOT		3	2013 - 2022		1,088
Other Regions		10	2015 - 2030		3,517

Total		43			9,296


	2013		2014		2015		2016		2017
Capacity Expiring (MW)		1,369		55		1,730		4		2,083

(a)	Excludes contracts with CENG.

Fuel

The following table shows sources of electric supply in GWh for 2012 and 2011:


	Source of Electric Supply^(a)
	2012		2011
Nuclear		139,862		139,297
Purchases—non-trading portfolio ^(b)		91,994		18,908
Fossil		27,760		7,385
Renewable		4,079		4,253

Total supply		263,695		169,843

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

(b)	Includes purchases in 2012 pursuant to Generation’s PPA with CENG. See Note 22 of the Combined Notes to Consolidated Financial Statements for additional information.

The fuel costs for nuclear generation are less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its wholesale and retail load servicing 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 2016. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2020. All of Generation’s enrichment requirements have been contracted through 2017. Contracts for fuel fabrication have been obtained through 2018. 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.

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

Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures. Generation also hedges forward price risk, using both over-the-counter and exchange-traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates and Note 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.

Power Marketing

Generation’s integrated business 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 maintains an effective supply strategy through ownership of generation assets and power purchase and lease agreements. 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 depending on

the type of underlying asset. Generation secures contracted generation as part of its overall strategic plan, with objectives such as obtaining low-cost energy supply sources to meet its physical delivery obligations to both wholesale and retail customers and assisting customers to meet renewable portfolio standards. Generation may buy power to meet the energy demand of its customers, including ComEd, PECO and BGE. Generation sells electricity, natural gas, and related products and solutions to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets. Generation’s customer facing operations combine a unified sales force with a customer-centric model that leverages technology to broaden the range of products and solutions offered, which Generation believes promotes stronger customer relationships. This model focuses on efficiency and cost reduction, which provides a platform that is scalable and able to capitalize on opportunities for future growth.

Generation’s purchases may be for more than the energy demanded by Generation’s customers. Generation then sells this open position, along with capacity not used to meet customer demand, in the wholesale electricity markets. Where necessary, Generation also purchases 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. Generation actively manages these physical and contractual assets in order to derive incremental value. Additionally, Generation is involved in the development, exploration, and harvesting of oil, natural gas and natural gas liquids properties.

Price Supply Risk Management

Generation 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. Generation is exposed to relatively greater commodity price risk beyond 2013 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, 2012, the percentage of expected generation hedged for the major reportable segments was 94%-97%, 62%-65% and 27%-30% for 2013, 2014, and 2015, 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, including purchased power from CENG. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including sales to ComEd, PECO and BGE 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. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and value-at-risk limits, to manage exposure to market risk. Additionally, the corporate risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retail power marketing activities. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

At December 31, 2012, Generation’s short and long-term commitments relating to the purchase of energy and capacity from and to unaffiliated utilities and others were as follows:


	Net Capacity Purchases ^(a)		Power-Related Purchases ^(b)		Transmission Rights Purchases ^(c)		Purchased Energy from CENG		Total
2013	$	374	$	95	$	28	$	777	$	1,274
2014		353		69		26		516		964
2015		350		25		13		—		388
2016		266		11		2		—		279
2017		203		3		2		—		208
Thereafter		469		5		34		—		508

Total	$	2,015	$	208	$	105	$	1,293	$	3,621

(a)

Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2012, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain capacity charges which are contingent on plant availability.

(b)	Power-Related Purchases include firm REC purchase agreements. The table excludes renewable energy purchases 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.

As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase agreements with CENG were modified to be unit-contingent through the end of their original term in 2014. Under these agreements, CENG has the ability to fix the energy price on a forward basis by entering into monthly energy hedge transactions for a portion of the future sale, while any unhedged portions will be provided at market prices by default. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG’s nuclear plants at market prices. Generation discloses in the table above commitments to purchase from CENG at fixed prices. All commitments to purchase from CENG at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 22 of the Combined Notes to Consolidated Financial Statements for more details on this arrangement.

Capital Expenditures

Generation’s business is capital intensive and requires significant investments in nuclear fuel and energy generation assets and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2013 are as follows:


(in millions)
Nuclear fuel ^(a)	$	1,000
Production plant		1,000
Renewable energy projects ^(b)		575
Uprates		225
Other		50

Total	$	2,850

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

(b)	Primarily relates to expenditures for the completion of the Antelope Valley development project.

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 NERC mandatory reliability standards.

ComEd’s retail service territory has an area of approximately 11,400 square miles and an estimated population of 9 million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of 2.7 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 2013 to 2066. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

ComEd’s kWh deliveries 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 July 20, 2011, and was 23,753 MWs; its highest peak load during a winter season occurred on January 15, 2009, and was 16,328 MWs.

Retail Electric Services

Under Illinois law, transmission and distribution services are regulated, while electric customers are allowed to purchase electricity supply from a competitive retail electric supplier.

Electric revenues and purchased power expense are affected by fluctuations in customers’ purchases from competitive retail electric suppliers. All ComEd customers have the ability to purchase energy from an alternative retail electric supplier. The customer choice activity affects revenue collected from customers related to supplied energy; however, that activity has no impact on electric revenue net of purchased power expense. ComEd’s cost of electric supply is passed directly through to default service customers without markup and those rates are subject to adjustment monthly to recover or refund the difference between ComEd’s actual cost of electricity delivered and the amount included in rates. For those customers that choose a competitive electric generation supplier, ComEd acts as the billing agent but does not record revenues or expenses related to the electric supply. ComEd remains the distribution service provider for all customers in its service territory and charges a regulated rate for distribution service. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information on customer switching to alternative electric generation suppliers, and Note 3 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electricity procurement process and for additional information.

Under Illinois law, ComEd is required to deliver electricity to all customers. ComEd’s obligation to provide generation supply service, which is referred to as a POLR obligation, primarily varies by customer size. ComEd’s obligation to provide such service to residential customers and other small customers with demands of under 100 kWs continues for all customers who do not or cannot choose a

competitive electric generation supplier or who choose to return to ComEd after taking service from a competitive electric generation supplier. ComEd does not have a fixed-price generation supply service obligation to most of its largest customers with demands of 100 kWs or greater, as this group of customers has previously been declared competitive. Customers with competitive declarations may still purchase power and energy from ComEd, but only at hourly market prices.

Energy Infrastructure Modernization Act (EIMA). Since 2011, ComEd’s distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois’ electric utility infrastructure. In addition, as long as ComEd is subject to EIMA, ComEd will fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates.

ComEd files an annual reconciliation of the revenue requirement in effect in a given year to reflect the actual costs that the ICC determines are prudently and reasonably incurred for such year. Under the terms of EIMA, ComEd’s target rate of return on common equity is subject to reduction if ComEd does not deliver the reliability and customer service benefits, as defined, it has committed to over the ten-year life of the investment program. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Electric Distribution Rate Cases. The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. On February 23, 2012, the ICC issued an order in the remand proceeding requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation. On March 26, 2012, ComEd filed a notice of appeal. ComEd has recognized for accounting purposes its best estimate of any refund obligation.

On May 24, 2011, the ICC issued an order in ComEd’s 2010 electric distribution rate case, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd’s annual delivery service revenue requirement and a 10.5% rate of return on common equity. The order has been appealed to the Court by several parties. ComEd cannot predict the results of these appeals. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electric distribution rate cases.

Procurement-Related Proceedings. Since June 2009, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement Legislation, ComEd hedged the price of a significant portion of energy purchased in the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. As required by EIMA, in February 2012 the IPA completed procurement events for energy and REC requirements for the June 2013 through December 2017 period. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s energy commitments.

Continuous Power Interruption. The Illinois Public Utilities Act 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) more than 30,000 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. See Note 19—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Construction Budget

ComEd’s business is capital intensive and requires significant investments primarily in energy transmission and distribution facilities, to ensure the adequate capacity, reliability and efficiency of its system. Based on PJM’s RTEP, ComEd has various construction commitments, as discussed in Note 3 of the Combined Notes to Consolidated Financial Statements. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2013 is $1,400 million, which includes RTEP projects and infrastructure modernization resulting from EIMA. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources for further information.

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 gas 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 distribution 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 areas 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 NERC mandatory reliability standards.

PECO’s combined electric and natural gas retail service territory has an area of approximately 2,100 square miles and an estimated population of 4.0 million. PECO provides electric distribution service in an area of approximately 1,900 square miles, with a population of approximately 3.9 million, including approximately 1.5 million in the City of Philadelphia. PECO provides natural gas distribution service in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to the City of Philadelphia, with a population of approximately 2.4 million. PECO delivers electricity to approximately 1.6 million customers and natural gas to approximately 497,000 customers.

PECO has the necessary authorizations to provide regulated electric and natural gas distribution 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; however, PECO does not consider those situations as posing a material competitive or financial threat.

PECO’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. PECO’s highest peak load occurred on July 22, 2011 and was 8,983 MW; its highest peak load during winter months occurred on December 20, 2004 and was 6,838 MW.

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

Retail Electric Services

PECO’s retail electric sales and distribution service revenues are derived pursuant to rates regulated by the PAPUC. Pennsylvania permits competition by EGSs for the supply of retail electricity while retail transmission and distribution service remains regulated under the Competition Act. At December 31, 2012, there were 77 alternative EGSs serving PECO customers. At December 31, 2012, the number of retail customers purchasing energy from an alternative EGS was 496,500 representing approximately 31% of total retail customers. Retail deliveries purchased from EGSs represented approximately 66% of PECO’s retail kWh sales for the year ended December 31, 2012. Customers that choose an alternative EGS are not subject to rates for PECO’s electric supply procurement costs and retail transmission service charges. PECO presents on customer bills its electric supply Price to Compare, which is updated quarterly, to assist customers with the evaluation of offers from alternative EGSs.

Customer choice program activity affects revenue collected from customers related to supplied energy; however, that activity has no impact on electric revenue net of purchased power expense or PECO’s financial position. PECO’s cost of electric supply is passed directly through to default service customers without markup and those rates are subject to adjustment at least quarterly to recover or refund the difference between PECO’s actual cost of electricity delivered and the amount included in rates through the GSA. For those customers that choose an alternative EGS, PECO acts as the billing agent but does not record revenues or purchase power and fuel expense related to this electric supply. PECO remains the distribution service provider for all customers in its service territory and charges a regulated rate for distribution service.

Procurement Proceedings. PECO’s electric supply for its customers is procured through contracts executed in accordance with its PAPUC-approved DSP Programs. PECO has entered into contracts with PAPUC-approved bidders, including Generation, as part of its DSP I competitive procurements conducted since June 2009 for its default electric supply beginning January 2011, which include fixed price full requirement contracts for all procurement classes, spot market price full requirements contracts for the commercial and industrial procurement classes, and block energy contracts for the residential procurement class. In September 2012, PECO completed its last competitive procurement for electric supply under its current DSP Program, which expires on May 31, 2013.

On October 12, 2012, the PAPUC approved PECO’s second DSP Program, which was filed with the PAPUC in January 2012. The plan outlines how PECO will purchase electric supply for default service customers from June 1, 2013 through May 31, 2015. Pursuant to the second DSP Program, PECO will procure electric supply through five competitive procurements for fixed price full requirements contracts of two years or less for the residential and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes beginning in June 2013.

The second DSP Program also includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning April 1, 2014. PECO expects to file its plan for CAP customers by May 1, 2013.

See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Smart Meter, Smart Grid and Energy Efficiency Programs

Smart Meter and Smart Grid Programs. In April 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan, which was filed in accordance with the requirements of Act 129. Also, in April 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA of 2009. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project—Smart Future Greater Philadelphia. The SGIG funds are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. On January 18, 2013, PECO filed with the PAPUC its universal deployment plan for approval of its proposal to deploy the remainder of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million and $120 million on its smart meter and smart grid infrastructure, respectively, before considering the $200 million SGIG.

See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Energy Efficiency Programs. PECO’s approved four-year Phase I EE&C plan totals approximately $328 million and sets forth how PECO will meet the required reduction targets established by Act 129’s EE&C provisions. PECO’s plan includes a 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. Under Act 129’s EE&C provisions, PECO was required to reduce peak demand by a minimum of 4.5% of its annual system peak demand in the 100 hours of highest demand by May 31, 2013. The peak demand period ended on September 30, 2012 and PECO will report its compliance with the reduction targets in a preliminary filing with the PAPUC on March 1, 2013. The final compliance report is due to the PAPUC by November 15, 2013. In addition, PECO is required to reduce electric consumption in its service territory by 3% through May 31, 2013.

On August 2, 2012, the PAPUC issued its Phase II EE&C implementation order, under which the PAPUC has established PECO’s three year cumulative consumption reduction target at 2.9%. PECO filed its three year EE&C Phase II plan with the PAPUC on November 1, 2012. The plan sets forth how PECO will reduce electric consumption by at least 2.9% in its service territory for the period June 1, 2013 through May 31, 2016.

See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Natural Gas

PECO’s natural gas sales and distribution service revenues are derived through natural gas deliveries at rates regulated by the PAPUC. PECO’s purchased natural gas cost rates, which represent a significant 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 without markup through the PGC.

PECO’s natural gas customers have the right to choose their natural gas suppliers or to purchase their gas supply from PECO at cost. At December 31, 2012, the number of retail customers purchasing natural gas from a competitive natural gas supplier was 53,600, representing approximately 11% of total retail customers. Retail deliveries purchased from competitive natural gas suppliers represented approximately 16% of PECO’s mmcf sales for the year ended December 31, 2012. PECO provides distribution, billing, metering, installation, maintenance and emergency response services at regulated rates to all its customers in its service territory.

Procurement Proceedings. PECO’s natural gas supply is purchased from a number of suppliers primarily under long-term firm transportation contracts for terms of up to two years in accordance with its annual PAPUC PGC settlement. PECO’s aggregate annual firm supply under these firm transportation contracts is 35 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 2012-2013 heating season planned supplies.

See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Construction Budget

PECO’s business is capital intensive and requires significant investments primarily in electric transmission and electric and natural gas distribution facilities to ensure the adequate capacity, reliability and efficiency of its system. PECO, as a transmission facilities owner, has various construction commitments under PJM’s RTEP as discussed in Note 3 of the Combined Notes to Consolidated Financial Statements. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2013 is $569 million, which includes RTEP projects and capital expenditures related to the smart meter and smart grid project net of expected SGIG DOE reimbursements.

BGE

BGE is engaged principally in the purchase and regulated retail sale of electricity and the provision of transmission and distribution services to retail customers in central Maryland, including the City of Baltimore, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services to retail customers in central Maryland, including the City of Baltimore. BGE is a public utility under the Public Utilities Article of the Maryland Annotated Code subject to regulation by the MDPSC as to electric and gas distribution rates and service, the issuances of certain securities and certain other aspects of BGE’s operations. BGE is a public utility under the Federal Power Act subject to regulation by FERC as to transmission rates and certain other aspects of BGE’s business and by the U.S. Department of Transportation as to pipeline safety and other areas of gas operations. Specific operations of BGE are subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, BGE is also subject to NERC mandatory reliability standards.

BGE serves an estimated population of 2.8 million in its 2,300 square mile combined electric and gas retail service territory. BGE provides electric distribution service in an area of approximately 2,300 square miles and gas distribution service in an area of approximately 810 miles, both with a population of approximately 2.8 million, including approximately 621,000 in the City of Baltimore. BGE delivers electricity to approximately 1.2 million customers and natural gas to approximately 655,000 customers.

BGE has the necessary authorizations to provide regulated electric and natural gas distribution services in the various municipalities and territories in which it now supplies such services. With respect to electric distribution service, BGE’s authorizations consist of charter rights, a state-wide franchise grant and a franchise grant from the City of Baltimore. The franchise grants are not exclusive and are perpetual. With respect to natural gas distribution service, BGE’s authorizations consist of charter rights, a perpetual state-wide franchise grant, and franchises granted by all the municipalities and/or governmental bodies in which BGE now supplies services. The franchise grants are not exclusive; some are perpetual and some are for a limited duration, which BGE anticipates being able to extend or replace prior to expiration.

BGE’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.

BGE’s highest peak load occurred on July 21, 2011 and was 7,236 MW; its highest peak load during winter months occurred on February 6, 2007 and was 6,347 MW.

BGE’s natural gas sales are generally higher during the winter months when cold temperatures create demand for winter heating. BGE’s highest daily natural gas send out occurred on February 5, 2007 and was 840 mmcf.

The demand for electricity and gas is affected by weather and usage conditions. The MDPSC has allowed BGE to record a monthly adjustment to its electric and gas distribution revenues from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’s electric and gas distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This adjustment allows BGE to recognize revenues at MDPSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period (referred to as “revenue decoupling”). Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. BGE bills or credits impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

Retail Electric Services

BGE’s retail electric sales and distribution service revenues are derived from electricity deliveries at rates regulated by the MDPSC. As a result of the deregulation of electric generation in Maryland effective July 1, 2000, all customers can choose their EGS. While BGE does not sell electric supply to all customers in its service territory, BGE continues to deliver electricity to all customers and provides meter reading, billing, emergency response, and regular maintenance services. Customer choice program activity affects revenue collected from customers related to supplied energy; however, that activity has no impact on electric revenue net of purchased power expense or BGE’s financial position. At December 31, 2012, there were 53 alternative EGSs serving BGE customers. At December 31, 2012, the number of retail customers purchasing energy from an alternative EGS was 362,117, representing approximately 29% of total retail customers. Retail deliveries purchased from EGSs represented approximately 60% of BGE’s retail kWh sales for the year ended December 31, 2012.

BGE is obligated to provide market-based SOS to all of its electric customers. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes a commercial and industrial shareholder return component and an incremental cost component. Bidding to supply BGE’s market-based SOS occurs through a competitive bidding process approved by the MDPSC. Successful bidders, which may include Generation, will execute contracts with BGE for terms of three months or two years.

BGE is obligated by the MDPSC to provide several variations of SOS to commercial and industrial customers depending on customer load.

Electric Distribution Rate Cases. In December 2010, the MDPSC issued an abbreviated electric rate order authorizing BGE to increase electric distribution rates for service rendered on or after December 4, 2010 by no more than $31 million. In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated combined electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs are being recovered over a 5-year period beginning in December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. The regulatory asset for the storm costs earns the authorized

rate of return. On July 27, 2012, BGE filed a combined application for increases to its electric and gas base rates with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October 22, 2012, BGE filed an updated application to request an increase of $131 million to its electric distribution base revenue requirement. The new electric distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

Smart Meter and Energy Efficiency Programs

Smart Meter Programs. In August 2010, the MDPSC approved BGE’s $480 million, SGIP, which includes deployment of a two-way communications network, 2 million smart electric and gas meters and modules, new customer pricing programs, a new customer web portal and numerous enhancements to BGE operations. Also, in April 2010, BGE entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA of 2009. Under the SGIG, BGE has been awarded $200 million, the maximum grant allowable under the program, to support its Smart Grid, Peak Rewards and CC&B initiatives. The SGIG funding is being used to significantly reduce the rate impact of those investments on BGE customers. In total, through the ten year life of the Smart Grid program, BGE plans to spend up to $835 million on its smart grid and smart meter infrastructure.

Energy Efficiency Programs. BGE’s energy efficiency programs include a 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. The MDPSC initially approved a full portfolio of conservation programs as well as a customer surcharge to recover the associated costs. This customer surcharge is updated annually. In December 2011, the MDPSC approved BGE’s conservation programs for implementation in 2012 through 2014.

Natural Gas

BGE’s natural gas sales are derived pursuant to a MBR mechanism that applies to customers who buy their gas from BGE. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. Customer choice program activity affects revenue collected from customers related to supplied natural gas; however, that activity has no impact on gas revenue net of purchased power expense or BGE’s financial position. At December 31, 2012, there were 27 alternative NGSs serving BGE customers. At December 31, 2012, the number of retail customers purchasing fuel from an alternative NGS was 143,351, representing approximately 22% of total retail customers. Retail deliveries purchased from NGSs represented approximately 56% of BGE’s retail mmcf sales for the year ended December 31, 2012.

BGE must secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed price contracts are recovered under the MBR mechanism and are not subject to sharing. BGE meets its natural gas load requirements through firm pipeline transportation and storage entitlements. BGE’s current pipeline firm transportation entitlements to serve its firm loads are 362 mmcf per day.

BGE’s current maximum storage entitlements are 284 mmcf per day. To supplement its gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, BGE has:

•

a liquefied natural gas facility for the liquefaction and storage of natural gas with a total storage capacity of 1,000 mmcf and a daily capacity of 298 mmcf,

•

a liquefied natural gas facility for natural gas system pressure support with a total storage capacity of 5.8 mmcf and a daily capacity of 5.8 mmcf, and

•

a propane air facility and a mined cavern with a total storage capacity equivalent to 500 mmcf and a daily capacity of 81 mmcf.

BGE has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefying sufficient volumes of natural gas during the summer months for operations of its liquefied natural gas facility during peak winter periods. BGE historically has been able to arrange short-term contracts or exchange agreements with other gas companies in the event of short-term disruptions to gas supplies or to meet additional demand.

BGE also participates in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between shareholders and customers. BGE makes these sales as part of a program to balance its supply of, and cost of, natural gas.

Natural Gas Distribution Rate Cases. In December 2010, the MDPSC issued a rate order authorizing BGE to increase the gas distribution base revenue requirement for service rendered on or after December 4, 2010 by no more than $9.8 million. In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated combined electric and gas distribution rate order issued in December 2010. On July 27, 2012, BGE filed a combined application for increases to its electric and gas base rates with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October 22, 2012, BGE filed an updated application to request an increase of $45 million to its gas distribution base revenue requirement. The new gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

Construction Budget

BGE’s business is capital intensive and requires significant investments primarily in electric transmission and electric and natural gas distribution facilities to ensure the adequate capacity, reliability and efficiency of its system. BGE, as a transmission facilities owner, has various construction commitments under PJM’s RTEP as discussed in Note 3 of the Combined Notes to Consolidated Financial Statements. BGE’s most recent estimate of capital expenditures for plant additions and improvements for 2013 is $663 million, which includes capital expenditures related to the SGIP net of expected SGIG DOE reimbursements.

ComEd, PECO and BGE

Transmission Services

ComEd, PECO and BGE provide unbundled transmission service under rates approved 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, PECO and BGE, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. ComEd, PECO and BGE are required to comply with FERC’s Standards of Conduct regulation 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, PECO and BGE are members of PJM and provide regional transmission service pursuant to the PJM Tariff. ComEd, PECO, BGE 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.

PECO default service customers are charged for retail transmission services through a rider designed to recover PECO’s PJM transmission network service charges and RTEP charges on a full and current basis in accordance with the 2010 electric distribution rate case settlement.

The transmission rate in the PJM Open Access Transmission Tariff under which PECO incurs costs to serve its default service customers and earns revenue as a transmission facility owner is a FERC-approved rate. This is the rate that all load serving entities in the PECO transmission zone pay for wholesale transmission service.

BGE’s transmission rates are established based on a formula that was approved by FERC in April 2006. 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.

See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding transmission services.

Employees

As of December 31, 2012, Exelon and its subsidiaries had 26,057 employees in the following companies, of which 8,665 or 33% were covered by collective bargaining agreements (CBAs):


	IBEW Local 15 ^(a)		IBEW Local 614 ^(b)		Other CBAs ^(c)		Total Employees Covered by CBAs		Total Employees
Generation		1,701		110		1,889		3,700		12,116
ComEd		3,571		—		—		3,571		5,902
PECO		—		1,286		—		1,286		2,453
BGE		—		—		—		—		3,360
Other ^(d)		82		—		26		108		2,226

Total		5,354		1,396		1,915		8,665		26,057

(a)	A separate CBA between ComEd and IBEW Local 15, ratified on October 10, 2012, covers approximately 24 employees in ComEd’s System Services Group. Generation’s and ComEd’s separate CBAs with IBEW Local 15 will expire in 2013.

(b)

1,286 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 110 employees.

(c)

During 2012, Generation finalized CBAs with the Security Officer unions at Byron, Clinton and TMI, which expire between 2015 and 2016. During 2011, Generation finalized CBAs with the Security Officer unions at Braidwood, Dresden, LaSalle and Quad Cities, which expire between 2014 and 2015. During 2009 and 2010, Generation entered into CBAs with the Security Officer unions at Oyster Creek and Limerick, which expire in 2013 and 2014, respectively. Additionally, during 2009, a 5-year agreement was reached with Oyster Creek Nuclear Local 1289, which will expire in 2015. In 2010, a 3-year agreement was negotiated with New England ENEH, UWUA Local 369, which will expire in 2014 and covers 10 employees.

(d)	Other includes shared services employees at BSC.

Environmental Regulation

General

Exelon, Generation, ComEd, PECO and BGE are subject to comprehensive and complex legislation regarding environmental matters by the U.S. Congress and by various state and local jurisdictions in which they operate their facilities. The Registrants are also subject to regulations administered by the U.S. EPA and various state and local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air, water, and solid and hazardous waste disposal.

The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice President, Corporate Strategy and Chief Sustainability Officer; the Corporate Environmental Strategy Director and the Environmental Regulatory Strategy Director, as well as senior management of Generation, ComEd, PECO and BGE. Performance of those individuals directly involved in environmental compliance and strategy 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 compliance with laws and regulations and its 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 BGE.

Air Quality

Air quality regulations promulgated by the U.S. EPA and the various state and local environmental agencies in Illinois, Maryland, Massachusetts, New York, Pennsylvania and Texas in accordance with the Federal Clean Air Act impose restrictions on emission of particulates, sulfur dioxide (SO₂), nitrogen oxides (NO_x), mercury and other pollutants and require permits for operation of emissions sources. Such permits have been obtained by Exelon’s subsidiaries and must be renewed periodically. The Clean Air Act establishes a comprehensive and complex national program to substantially reduce air pollution from power plants. Advanced emission controls for SO₂ and NOx have been installed at all of Generation’s co-owned bituminous coal-fired units.

See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding clean air regulation and legislation in the forms of the CSAPR and CAIR, the regulation of hazardous air pollutants from coal- and oil-fired electric generating facilities under MATS, and regulation of GHG emissions, in addition to NOVs issued to Generation and ComEd for alleged violations of the Clean Air Act.

During 2012, one of Generation’s co-owned facilities began a project to install environmental control equipment. Total costs incurred as of December 31, 2012 was approximately $39 million. The amount to be expended at Exelon and Generation in 2013, 2014 and 2015 is expected to total $70 million, $45 million and $5 million, respectively.

Water Quality

Under the 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. Certain of Generation’s power generation facilities

discharge industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension.

See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding the impact to Exelon of state permitting agencies’ administration of the Phase II rule implementing Section 316(b) of the Clean Water Act.

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 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. EPA 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. EPA 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, Maryland 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, PECO and BGE 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.

See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding solid and hazardous waste regulation and legislation.

Environmental Remediation

ComEd’s, PECO’s and BGE’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. The amount to be expended in 2013 at Exelon for compliance with environmental remediation related to contamination at former MGP sites is expected to total $57 million, consisting of $51 million, $6 million and $0 million at ComEd, PECO and BGE, respectively.

Generation’s environmental liabilities primarily arise from contamination at current and former generation and waste storage facilities. As of December 31, 2012, Generation has established an appropriate liability to comply with environmental remediation requirements including contamination

attributable to low level radioactive residues at a storage and reprocessing facility named Latty Avenue, and at a disposal facility named West Lake Landfill, both near St. Louis, Missouri related to operations conducted by Cotter Corporation, a former ComEd subsidiary.

In addition, Generation, ComEd, PECO and BGE may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.

See Notes 3 and 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental remediation efforts and related impacts to the Registrants’ results of operations, cash flows and financial position.

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, and as reported by the National Academy of Sciences in May 2011. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear, hydroelectric, wind and solar photovoltaic), 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 equivalent (CO₂e) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions, primarily at its fossil fuel-fired 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 combustion of fossil fuels represent the majority of Exelon’s direct GHG emissions in 2012, although only a small portion of Exelon’s electric supply is from fossil generating plants. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF₆) leakage in its electric transmission and distribution operations and refrigerant leakage from its chilling and cooling equipment as well as fossil fuel combustion in its motor vehicles and usage of electricity at its facilities. Despite its focus on low-carbon generation, 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 with climate change.

Climate Change Regulation. Exelon is, or may become, subject to climate change regulation or legislation at the Federal, regional and state levels.

International Climate Change Regulation. At the international level, the United States has not yet ratified the United Nations Kyoto Protocol, which was extended at the most recent meeting of the United Nations Framework on Climate Change Conference of the Parties (COP 18) in December 2012. The Kyoto Protocol now requires participating developed countries to cap GHG emissions at certain levels until 2020, when the new global agreement on emissions reduction is scheduled to become effective. The new global agreement has been agreed to in concept and further development of its GHG emissions reductions is scheduled to begin in 2015. At this point, there is much debate about the different levels of emission reductions that will be required for developed and developing countries. Another significant outcome of the COP 18 was a re-examination of the long-term temperature goal which could influence international climate policy by the United Nations.

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, including the enactment of federal climate change legislation. It is highly uncertain whether Federal

legislation to reduce GHG emissions will be enacted. If such legislation is adopted, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits.

The U.S. EPA is addressing the issue of carbon dioxide (CO₂) emissions regulation for new and existing electric generating units through the Section 111 NSPS under the existing provisions of the Clean Air Act. A proposed Section 111(b) regulation for new units is to be finalized in spring 2013, and may result in material costs of compliance for CO₂ emissions for new fossil-fuel electric generating units. The U.S. EPA is also expected to propose a Section 111(d) rule in 2013 to establish CO₂ emission regulations for existing stationary sources.

Regional and State Climate Change Legislation and Regulation. After a two-year program review, the nine northeast and mid-Atlantic states currently participating in the RGGI released an updated RGGI Model Rule and Program Review Recommendations Summary on February 7, 2013. Under the updated RGGI program, which must be approved pursuant to the applicable legislative and/or regulatory process in each RGGI State, the regional RGGI CO₂ budget would be reduced, starting in 2014, from its current 165 million ton level to 91 million tons, with a 2.5 percent reduction in the cap level each year between 2015-2020. Included in the new program are provisions for cost containment reserve (CCR) allowances, which will become available if the total demand for allowances, above the CCR trigger price, exceeds the number of CO₂ allowances available for purchase at auction. (CCR rigger prices are $4 in 2014, $6 in 2015, $8 in 2016 and $10 in 2017, rising 2.5 percent thereafter to account for inflation). Such an outcome could put modest upward pressure on wholesale power prices; however, the specifics are currently uncertain.

At the state level, on December 18, 2009, Pennsylvania issued the state’s final Climate Change Action Plan. The plan sets as a target a 30 percent reduction in GHG emissions by 2020. The Climate Change Advisory Committee continues to meet quarterly to review Climate Action Work Plans for the residential, commercial and industrial sectors. The Climate Change Action Plan does not impose any requirements on Generation or PECO at this time.

The Maryland Commission on Climate Change released its climate action plan on August 27, 2008, recommending that the state begin implementing 42 greenhouse gas reduction strategies. One of the Plan’s policy recommendations, to adopt science-based regulatory goals to reduce Maryland’s GHG emissions, was realized with the passage of the Greenhouse Gas Emissions Reduction Act of 2009 (GGRA). The law requires Maryland to reduce its GHG emissions by 25 percent below 2006 levels by 2020. It directs the MDE to work with other state agencies to prepare an implementation plan to meet this goal. An interim plan was submitted to the Governor and the General Assembly during the 2012 legislative session, and the final GGRA plan is expected in February of 2013. The final GGRA plan is not expected to impose any additional requirements on BGE. Maryland targeted electricity consumption reduction goals required under the “Empower Maryland” program, and mandatory State participation in the Regional Greenhouse Gas Reduction Initiative (RGGI) Program will be listed as that sector’s contribution in the GGRA plan.

The Illinois Climate Change Advisory Group, created by Executive Order 2006-11 on October 5, 2006, made its final recommendations on September 6, 2007 to meet the Governor’s GHG reduction goals. At this time, the only requirements imposed by the state are the energy efficiency and renewable portfolio standards in the Illinois Power Act that apply to ComEd.

Exelon’s Voluntary Climate Change Efforts. In a world increasingly concerned about global climate change and regulatory action to reduce GHG, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon remains one of the largest, lowest carbon electric generators in the United States: nuclear for base load, natural gas for marginal and peak demand,

hydro and pumped storage, and supplemental wind and solar renewables. As further legislation and regulation imposing requirements on emissions of GHG and air pollutants are promulgated, Exelon’s low carbon, low emission generation fleet will position the company to benefit from its comparative advantage over other generation fleets.

With the announcement in 2008 of Exelon 2020, Exelon set a voluntary goal to reduce, offset or displace more than 15.7 million metric tonnes of GHG emissions per year by 2020. Exelon updated that goal in 2012 following the Constellation merger to account for the integration of former Constellation GHG goals. The updated Exelon 2020 goal is to reduce, offset or displace more than 17.5 million metric tonnes of GHG emissions by 2020. The Exelon 2020 goal encompasses three broad areas of focus: reducing or offsetting Exelon’s own carbon footprint (with the year the asset/operations were acquired by Exelon as the baseline), helping customers and communities reduce their GHG emissions, and offering more low-carbon electricity in the marketplace.

Efforts to achieve the Exelon 2020 goal will be supported by the company’s current business plans as well as future initiatives that will be integrated into the annual business planning process. This includes a periodic review and refinement of Exelon 2020 initiatives in light of changing market conditions, regulations, technology and other factors that affect the merit of various GHG abatement options. 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.

Renewable and Alternative Energy Portfolio Standards

Twenty-nine states and the District of Columbia have adopted some form of RPS requirement. As previously described, Illinois, Pennsylvania and Maryland 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 adopt such legislation in the future.

The Illinois Settlement Legislation required that procurement plans implemented by electric utilities include cost-effective renewable energy resources or approved equivalents such as RECs 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 or approved equivalents subject to legislated rate impact criteria. As of December 31, 2012, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois Settlement Legislation. See Note 3 and Note 19 of the Combined Notes to Consolidated Financial Statements for additional information.

The AEPS Act was effective for PECO on January 1, 2011, following the expiration of PECO’s transition period. During 2012, PECO was required to supply approximately 4.0% and 6.2% of electric energy generated from Tier I (including solar, wind power, low-impact hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy, coal mine methane and black liquor generated within Pennsylvania) and Tier II (including waste coal, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing wood and by-products of the pulping process and wood, distributed generation systems and integrated combined coal gasification technology) alternative energy resources, respectively, as measured in AECs. The compliance requirements will incrementally escalate to 8.0% for Tier I and 10.0% for Tier II by 2021. In order to comply with these requirements, PECO entered into agreements with varying terms with accepted bidders, including Generation, to purchase non-solar Tier I, solar Tier 1 and Tier II AECs. PECO also purchases AECs through its DSP Program full requirement contracts.

Section 7-703 of the Public Utilities Article in Maryland sets forth the RPS requirement, which applies to all retail electricity sales in Maryland by electricity suppliers. The RPS requirement requires that suppliers obtain a specified percentage of the electricity it sells from Tier 1 sources (solar, wind, biomass, methane, geothermal, ocean, fuel cell, small hydroelectric, and poultry litter) and Tier 2 sources (hydroelectric, other than pump storage generation, and waste-to-energy). The RPS requirement began in 2006, requiring that suppliers procure 1.0% and 2.5% from Tier 1 and Tier 2 sources, respectively, escalating in 2022 to 22.0% from Tier 1 sources, including at least 2.0% from solar energy, and 0.0% from Tier 2 sources. In 2012, 6.5% were required from Tier 1 renewable sources, including at least 0.1% derived from solar energy, and 2.5% from Tier 2 renewable sources. The wholesale suppliers that supply power to the state’s utilities through the SOS procurement auctions have the obligation, by contract with those utilities, to comply with and provide its proportional share of the RPS requirements.

Similar to ComEd, PECO and BGE, Generation’s retail electric business must source a portion of the electric load it serves in many of the states in which it does business from renewable resources or approved equivalents such as RECs. Potential regulation and legislation regarding renewable and alternative energy resources could increase the pace of development of wind and other renewable/alternative energy resources, which could put downward pressure on wholesale market prices for electricity in some markets where Exelon operates generation assets. At the same time, such developments may present some opportunities for sales of Generation’s renewable power, including from wind, solar, hydroelectric and landfill gas.

See Note 3 and Note 19 of the Combined Notes to Consolidated Financial Statements for additional information.

Executive Officers of the Registrants as of February 21, 2013

Exelon


Name	Age	Position	Period
Crane, Christopher M.	54	Chief Executive Officer, Exelon;	2012 - Present
		Chairman, ComEd, PECO & BGE	2012 - Present
		President, Exelon; President, Generation	2008 - Present
		Chief Operating Officer, Exelon	2008 - 2012
		Chief Operating Officer, Generation	2007 - 2010
		Executive Vice President, Exelon	2007 - 2008
Shattuck III, Mayo A.	58	Executive Chairman, Exelon	2012 - Present
		Chairman, President and	2001 - 2012
		Chief Executive Officer, Constellation
Cornew, Kenneth W.	47	Executive Vice President and Chief Commercial Officer, Exelon;	2012 - Present
		President and Chief Executive Officer, Constellation	2012 - Present
		Senior Vice President, Exelon; President, Power Team	2008 - 2012
		Senior Vice President, Trading and Origination, Power Team	2007 - 2008
O’Brien, Denis P.	52	Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities	2012 - Present
		Chief Executive Officer, PECO; Executive Vice President, Exelon	2007 - 2012
		President and Director, PECO	2003 - 2012


Name	Age	Position	Period
Pramaggiore, Anne R.	54	Chief Executive Officer, ComEd	2012 - Present
		President, ComEd	2009 - Present
		Chief Operating Officer, ComEd	2009 - 2012
		Executive Vice President, Customer Operations, Regulatory and External Affairs, ComEd	2007 - 2009
Adams, Craig L.	60	President and Chief Executive Officer, PECO	2012 - Present
		Senior Vice President and Chief Operating Officer, PECO	2007 - 2012
DeFontes Jr., Kenneth W.	62	President and Chief Executive Officer, BGE	2004 - Present
		Senior Vice President, Constellation Energy	2004 - 2012
Gillis, Ruth Ann M.	58	Executive Vice President, Exelon	2008 - Present
		Chief Administrative Officer, Exelon	2010 - Present
		President, Exelon Business Services Company	2005 - Present
		Chief Diversity Officer, Exelon	2009 - 2012
		Senior Vice President, Exelon	2002 - 2008
Von Hoene Jr., William A.	59	Senior Executive Vice President and Chief Strategy Officer, Exelon	2012 - Present
		Executive Vice President, Finance and Legal, Exelon	2009 - 2012
		Executive Vice President and General Counsel, Exelon	2008 - 2009
		Senior Vice President, Exelon Business Services Company	2004 - 2009
		Senior Vice President, Exelon	2006 - 2008
Thayer, Jonathan W.	41	Executive Vice President and Chief Financial Officer, Exelon	2012 - Present
		Senior Vice President and Chief Financial Officer, Constellation Energy; Treasurer, Constellation Energy	2008 - 2012
		Vice President, Constellation Energy	2004 - 2008
Glace, Joseph R.	52	Senior Vice President, Exelon	2012 - Present
		Chief Risk Officer, Exelon	2008 - Present
		Vice President, Exelon	2008 - 2012
DesParte, Duane M.	50	Vice President and Corporate Controller, Exelon	2008 - Present
		Vice President, Finance, Exelon Business Services Company	2007 - 2008

Generation


Name	Age	Position	Period
Crane, Christopher M.	54	Chief Executive Officer, Exelon; Chairman, ComEd, PECO & BGE	2012 - Present
		President, Exelon; President, Generation	2008 - Present
		Chief Operating Officer, Exelon	2008 - 2012
		Chief Operating Officer, Generation	2007 - 2010
		Executive Vice President, Exelon	2007 - 2008
Cornew, Kenneth W.	47	Executive Vice President and Chief Commercial Officer, Exelon; President and Chief Executive Officer, Constellation	2012 - Present
		Senior Vice President, Exelon; President, Power Team	2008 - 2012
		Senior Vice President, Trading and Origination, Power Team	2007 - 2008


Name	Age	Position	Period
Pacilio, Michael J.	52	President, Exelon Nuclear; Senior Vice President and Chief Nuclear Officer, Generation	2010 - Present
		Chief Operating Officer, Exelon Nuclear	2007 - 2010
DeGregorio, Ronald	50	Senior Vice President, Generation; President, Exelon Power	2012 - Present
		Chief Integration Officer, Exelon	2011 - 2012
		Chief Operating Officer, Exelon Transmission Company	2010 - 2011
		Senior Vice President, Mid-Atlantic Operations, Exelon Nuclear	2007 - 2010
Wright, Bryan P.	46	Senior Vice President and Chief Financial Officer, Generation	2013 - Present
		Senior Vice President, Corporate Finance, Exelon	2012 - 2013
		Chief Accounting Officer, Constellation Energy	2009 - 2012
		Vice President and Controller, Constellation Energy	2008 - 2012
		Vice President and Controller, Constellation Energy Resources	2007 - 2008
Aiken, Robert	46	Vice President and Controller, Generation	2012 - Present
		Executive Director and Assistant Controller, Constellation	2011 - 2012
		Executive Director of Operational Accounting, Constellation Energy Commodities Group	2009 - 2011
		Vice President of International Accounting, Constellation Energy Commodities Group	2007 - 2009

ComEd


Name	Age	Position	Period
Pramaggiore, Anne R.	54	Chief Executive Officer, ComEd	2012 - Present
		President, ComEd	2009 - Present
		Chief Operating Officer, ComEd	2009 - 2012
		Executive Vice President, Customer Operations, Regulatory and External Affairs, ComEd	2007 - 2009
Donnelly, Terence R.	52	Executive Vice President and Chief Operating Officer, ComEd	2012 - Present
		Executive Vice President, Operations, ComEd	2009 - 2012
		Senior Vice President, Transmission and Distribution, ComEd	2007 - 2009
Trpik Jr., Joseph R.	43	Senior Vice President, Chief Financial Officer and Treasurer, ComEd	2009 - Present
		Vice President & Assistant Corporate Controller, Exelon Business Services Company	2007 - 2009
		Vice President and Assistant Corporate Controller, Exelon	2004 - 2009
Jensen, Val	57	Senior Vice President, Customer Operations, ComEd	2012 - Present
		Vice President, Marketing and Environmental Programs, ComEd	2008 - 2012
		Senior Vice President, ICF International	2006 - 2008


Name	Age	Position	Period
O’Neill, Thomas S.	50	Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd	2010 - Present
		Senior Vice President, Exelon	2009 - 2010
		Senior Vice President, New Business Development, Generation; Senior Vice President, New Business Development, Exelon	2009 - 2009
		Vice President, New Plant Development, Generation	2007 - 2009
Marquez Jr., Fidel	51	Senior Vice President, Governmental and External Affairs, Exelon	2012 - Present
		Senior Vice President, Customer Operations, ComEd	2009 - 2012
		Vice President of External Affairs and Large Customer Services, ComEd	2007 - 2009
Brookins, Kevin B.	51	Senior Vice President, Strategy & Administration, ComEd	2012 - Present
		Vice President, Operational Strategy and Business Intelligence, ComEd	2010 - 2012
		Vice President, Distribution System Operations, ComEd	2008 - 2010
		Vice President, Work Management and New Business	2007 - 2008
Anthony, J. Tyler	48	Senior Vice President, Distribution Operations, ComEd	2010 - Present
		Vice President, Transmission and Substations, ComEd	2007 - 2010
Waden, Kevin J.	41	Vice President, Comptroller, Accountant and Controller, ComEd	2009 - Present
		Director of Accounting Operations, ComEd	2007 - 2009

PECO


Name	Age	Position	Period
Adams, Craig L.	60	President and Chief Executive Officer, PECO	2012 - Present
		Senior Vice President and Chief Operating Officer, PECO	2007 - 2012
Barnett, Phillip S.	49	Senior Vice President and Chief Financial Officer, PECO	2007 - Present
		Treasurer, PECO	2012 - Present
Innocenzo, Michael A.	47	Senior Vice President, Operations, PECO	2012 - Present
		Vice President, Distribution System Operations and Smart Grid/Smart Meter, PECO	2010 - 2012
		Vice President, Distribution System Operations	2007 - 2010
Webster Jr., Richard G.	51	Vice President, Regulatory Policy and Strategy, PECO	2012 - Present
		Director of Rates and Regulatory Affairs	2007 - 2012
Murphy, Elizabeth A.	53	Vice President, Governmental and External Affairs, PECO	2012 - Present
		Director, Governmental & External Affairs, PECO	2007 - 2012
Alden, Mark F.	52	Vice President, Customer Operations, PECO	2009 - Present
		Vice President Gas, PECO	2007 - 2009


Name	Age	Position	Period
Diaz Jr., Romulo L.	66	Vice President and General Counsel, PECO	2012 - Present
		Vice President, Governmental and External Affairs, PECO	2009 - 2012
		Associate General Counsel, Exelon	2008 - 2009
		City Solicitor, City of Philadelphia	2005 - 2008
Bailey, Scott A.	36	Vice President and Controller, PECO	2012 - Present
		Assistant Controller, Generation	2011 - 2012
		Director of Accounting, Power Team	2007 - 2011

BGE


Name	Age	Position	Period
DeFontes Jr., Kenneth W.	62	President and Chief Executive Officer, BGE	2004 - Present
		Senior Vice President, Constellation Energy	2004 - 2012
Woerner, Stephen J.	45	Chief Operating Officer, BGE	2012 - Present
		Senior Vice President, BGE	2009 - Present
		Vice President and Chief Integration Officer, Constellation Energy	2011 - 2012
		Vice President and Chief Information Officer, Constellation Energy	2010 - 2011
		Vice President, Transformation, Constellation Energy	2009 - 2010
		Senior Vice President, Gas and Electric Operations and Planning, BGE	2007 - 2009
Khouzami, Carim V.	38	Vice President, Chief Financial Officer and Treasurer, BGE	2011 - Present
		Executive Director, Investor Relations, Constellation Energy	2009 - 2011
		Director, Corporate Strategy and Development, Constellation Energy	2008 - 2009
Case, Mark D.	51	Vice President, Strategy and Regulatory Affairs, BGE	2012 - Present
		Senior Vice President, Strategy and Regulatory Affairs, BGE	2007 - 2012
Dempsey, Mary E.	57	Vice President, Governmental Affairs, BGE	2012 - Present
		Executive Director, State Affairs, Constellation Energy	2010 - 2012
		Managing Director, Public Affairs, Constellation Energy	2008 - 2009
Mills, Jeannette M.	46	Vice President, Customer Operations, BGE	2012 - Present
		Chief Customer Officer, BGE	2011 - Present
		Senior Vice President, Customer Relations and Account Services, BGE	2008 - 2012
		Senior Vice President, Gas Operations and Planning, BGE	2007 - 2008
Gahagan, Daniel P.	59	Vice President and General Counsel, BGE	2007 - Present
Vahos, David M.	40	Vice President and Controller, BGE	2012 - Present
		Executive Director, Audit, Constellation	2010 - 2012
		Director, Finance, BGE	2006 - 2010

ITEM 1A.

RISK FACTORS

Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond the Registrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the RMC, which comprises officers of the Registrants, to identify and evaluate the most significant risks of the Registrants’ 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, PECO and BGE 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 known material risks that 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 by a Registrant to be material that may adversely affect its performance or financial condition in the future.

The Registrants’ most significant risks arise as a consequence of: (1) Generation’s position as a predominantly nuclear generator selling power into competitive energy markets, and (2) the role of ComEd, PECO and BGE as operators of electric transmission and distribution systems in three of the largest metropolitan areas in the United States. The Registrants’ major risks fall primarily under the following categories:

•

Market and Financial Risks. Exelon’s and Generation’s market and financial risks include the risk of price fluctuations in the wholesale and retail 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, in particular the price of natural gas and coal, that drive the wholesale market prices that Generation’s nuclear power plants receive, 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. In addition, the load serving and retail marketing activities compete for customers in a competitive environment which impacts the margins that Generation can earn and the volumes that it is able to serve.

•

Regulatory and Legislative Risks. The Registrants’ regulatory and legislative risks include 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 power into the competitive wholesale power markets at market-based prices. In addition, potential regulation and 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 might derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future. Also, regulatory actions in Illinois, Pennsylvania or Maryland could materially lower returns for ComEd, PECO and BGE, respectively.

•

Operational Risks. The Registrants’ operational risks include those risks inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe and effective operation of the nuclear facilities and the ability to effectively manage the 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. Additionally, the operating costs of ComEd, PECO and BGE and the opinions of customers and regulators of ComEd, PECO and BGE are

affected by those companies’ ability to maintain the reliability and safety of their energy delivery systems.

•

Risks Related to the Merger with Constellation. As a result of the merger with Constellation that closed on March 12, 2012, Exelon is subject to additional risks.

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 and retail power markets, which may negatively affect its results of operations. (Exelon and Generation)

Generation hedges the price risk associated with the generation it owns, or controls, through long-term power purchase agreements. Absent any hedging activity through fixed price transactions, Generation would be exposed to the risk of rising and falling spot market prices in the markets in which its assets are located, which would mean that Generation’s cash flows would vary accordingly.

The wholesale spot market price of electricity for each hour is generally determined by the marginal 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, and, therefore, the market price of power will reflect the market price of the marginal fuel. Consequently, changes in the market price of fossil fuels will cause comparable changes to the market price of power. For example, the use of new technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, placing further downward pressure on natural gas prices and has reduced Generation’s revenues. In addition, further delay or elimination of EPA air quality regulations could prolong the duration for which the cost of pollution is not factored into market prices which could reduce Generation’s revenue. Further, in the event that alternative generation resources, such as wind and solar, are mandated through RPS or otherwise subsidized or encouraged through climate legislation or regulation and added to the available generation supply such resources could displace a higher marginal cost fossil plant, which could reduce the price at which market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region, including Generation, would be able to sell their output. These events could adversely affect Generation’s financial condition, results of operations, and cash flows, and could also result in an impairment of certain long-lived assets.

The market price for electricity is also affected by changes in the demand for electricity. Worse than expected economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs can depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on market prices for electricity. The continued sluggish economy in the United States has in fact led to a slowdown in the growth of demand for electricity. If this continues, it could adversely affect the Registrants’ ability to fund other discretionary uses of cash such as growth projects or to pay dividends. In addition, the economic conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation’s results of operations through increased depreciation rates, impairment charges and accelerated future decommissioning costs. A slow recovery could result in a prolonged depression of or further decline in commodity prices, including low forward natural gas and power prices and low market volatility, which could also 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 in the power markets that are beyond its control and may negatively affect 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

under 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 risk as a result of default sharing mechanisms that exist within certain markets, primarily RTO’s and ISO’s, the purpose of which is to spread such risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. 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 remain 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 factors may decrease the value of decommissioning trust funds and benefit plan assets and increase the related obligations, which then could require significant additional funding. (Exelon, Generation, ComEd, PECO and BGE)

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 Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. 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 plan obligations. 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 or changes to Social Security or Medicare eligibility requirements may also increase the costs and funding requirements of the obligations related to the pension and other postretirement benefit plans. If future increases in pension and other postretirement costs as a result of reduced plan assets or other factors are not recoverable from ComEd, PECO and BGE customers, the results of operations and financial positions of ComEd, PECO and BGE could be negatively affected. Ultimately, if the Registrants are unable to manage the decommissioning trust funds and benefit plan assets and obligations, their results of operations, cash flows and financial positions could be negatively affected.

Unstable 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, PECO and BGE)

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. Disruptions in the capital and credit markets in the United States or abroad can adversely affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The Registrants’ access to funds under their credit facilities is dependent on the ability of the banks that 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. The inability to access capital markets or credit facilities, and 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 in order to reduce collateral-posting requirements, or a reduction in dividend payments or other discretionary uses of cash.

In addition, the Registrants have exposure to worldwide financial markets, including Europe. The ongoing European debt crisis has contributed to instability in global credit markets. Further disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2012, approximately 31%, or $2.5 billion, of the Registrants’ available credit facilities were with European banks. The credit facilities include $8.3 billion in aggregate total commitments of which $6.5 billion was available as of December 31, 2012. There were no borrowings under the Registrants’ credit facilities as of December 31, 2012. See Note 11 of the Combined Notes to the Consolidated Financial Statements for additional information on the credit facilities.

The strength and depth of competition in competitive energy markets depend 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 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 3 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 any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its trading counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs. (Exelon, Generation, ComEd, PECO and BGE)

Generation’s 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 its hedging arrangements 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 the applicable hedge, (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 credit rating 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.

PECO’s and BGE’s operating agreements with PJM and their natural gas procurement contracts contain collateral provisions that are affected by their credit ratings. If certain wholesale market conditions exist and PECO and BGE were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the form of letters of credit or cash, which may have material adverse effects upon their liquidity. PECO’s and BGE’s collateral requirements relating to their natural gas supply contracts are a function of market prices. Collateral posting requirements for PECO and BGE 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 or BGE were downgraded, they could experience higher borrowing costs as a result of the downgrade.

ComEd, PECO or BGE 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, PECO, or BGE in particular has deteriorated. ComEd, PECO or BGE could experience a downgrade if the current regulatory environments in Illinois, Pennsylvania or Maryland, respectively, become less predictable by materially lowering returns for utilities in the applicable state or adopting other measures to mitigate higher electricity prices. Additionally, the ratings for ComEd, PECO or BGE could be downgraded if their financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage their capital structure. In addition, changes in ratings methodologies by the agencies could also have a negative impact on the ratings of ComEd, PECO or BGE.

ComEd, PECO and BGE conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that ComEd, PECO and BGE are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate ComEd, PECO and BGE 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, PECO and BGE in the event of a reduction in the credit rating of Exelon. Despite these ringfencing measures, the credit ratings of ComEd, PECO or BGE 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, PECO or BGE, or all three. A reduction in the credit rating of ComEd, PECO or BGE could have a material adverse effect on ComEd, PECO or BGE, 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.

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 and fossil fuels 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.

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, cash flows or financial position.

Generation 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.

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 procurement contracts with ComEd, PECO, BGE 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 address 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, PECO and BGE)

Corporate Tax Reform. There exists the potential for comprehensive tax reform in the United States which may significantly change the tax rules that are applicable to U.S. domiciled corporations. Exelon cannot assess what the overall effect of such potential legislation would be on its results of operations and cash flows.

1999 sale of fossil generating assets. The IRS has challenged Exelon’s 1999 tax position on an involuntary conversion and like-kind exchange transaction. In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions and for the IRS to withdraw its assertion of a $110 million substantial understatement penalty related to the involuntary conversion position. Definitive documents consistent with the preliminary agreement were finalized in the fourth quarter of 2012. However, Exelon and IRS Appeals failed to reach a settlement on the like-kind exchange position. Exelon expects to initiate litigation on this matter during 2013.

As of March 31, 2013, if the IRS is successful in its challenge to the like-kind exchange position, Exelon’s potential cash outflow, including tax and after-tax interest, exclusive of penalties, that could become currently payable may be as much as $860 million, of which approximately $320 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless. In addition to attempting to impose tax on the like-kind exchange position, the IRS has asserted penalties for a substantial understatement of tax, which could result in an after-tax charge of $86 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 the like-kind exchange matter are unknown. See Note 12 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 and tax credits. See Notes 1 and 12 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, increased rates could lead to decreased volumes delivered. Both of these factors may decrease Generation’s, ComEd’s, PECO’s and BGE’s results from operations and cash flows. (Exelon, Generation, ComEd, PECO and BGE)

ComEd’s, PECO’s and BGE’s current procurement plans include purchasing power through contracted suppliers and in the spot market. ComEd’s and PECO’s costs of purchased power are charged to customers without a return or profit component. BGE’s SOS rates charged to customers recover BGE’s wholesale power supply costs and include an administrative fee which includes a shareholder return component and an incremental cost component. For PECO, purchased natural gas costs are charged to customers with no return or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism that compares the actual cost of gas to a market index. The difference between the actual cost and the market index is shared equally between shareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gas can result in declines in customer usage, lower revenues for electric transmission and distribution at ComEd, PECO and BGE, and for gas distribution at PECO, and potentially additional uncollectible accounts expense for ComEd, PECO and BGE. Also, ComEd’s, PECO’s and BGE’s cash flows can be affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.

Further, the impacts of economic downturns on ComEd, PECO and BGE customers and purchased natural gas costs for PECO and BGE customers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations may result in an increase in the number of uncollectible customer balances, which would negatively impact ComEd’s, PECO’s and BGE’s results from operations and cash flows. Generation’s customer supply activities face economic downturn risks similar to Exelon’s utility businesses, such as lower volumes sold and increase expense for uncollectible customer balances. As Generation increases its customer supply footprint, economic downturn impacts could negatively affect Generation’s results from operations and cash flows. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for further discussion of the Registrants’ credit risk.

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

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. Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Moderate temperatures adversely affect the usage of energy and resulting revenues at ComEd and PECO. Due to revenue decoupling, BGE recognizes revenues at MDPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period, and is not affected by actual weather with the exception of major storms. Extreme weather conditions or damage resulting from storms may stress ComEd’s, PECO’s and BGE’s transmission and distribution systems, communication systems and technology, 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, PECO’s and BGE’s results of operations and cash flows. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and may make period comparisons less relevant.

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 limiting water usage 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 markets are weak.

Certain long-lived assets and other 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, PECO and BGE)

Long-lived assets represent the single largest asset class on the Registrants’ statement of financial position. Specifically, long-lived assets account for 58%, 48%, 60%, 65% and 73% of total assets for Exelon, Generation, ComEd, PECO and BGE, respectively, as of December 31, 2012. In addition, the Registrants have significant balances related to unamortized energy contracts. See Notes 4 and 8 of the Combined Notes to Consolidated Financial Statements for additional information on Exelon’s unamortized energy contracts. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered when evaluating long-

lived assets for potential impairment. An impairment would require the Registrants to reduce the carrying value of the long-lived asset through a non-cash charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact on the Registrants’ results of operations.

Exelon and Generation have investments in certain generating plant projects, including the CENG nuclear joint venture with a carrying value of $1.8 billion as of December 31, 2012. These investments were acquired in the March 2012 Constellation transaction, and were recorded as equity method investments on the balance sheet at fair value on the merger date as part of purchase accounting. Exelon and Generation continuously monitor for issues that potentially could impact future profitability of these equity method investments and which could result in the recognition of an impairment loss if such issues indicate an other than temporary decline in value. Such impairment could have material adverse impacts on Exelon’s and Generation’s results of operations.

Exelon holds certain investments in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. On an annual basis, Exelon reviews the estimated residual values of these leased assets to determine whether any indications of impairment exist. In determining the estimate of residual value, the expectation of future market conditions, including commodity prices, is considered. An impairment would require Exelon to reduce the value of its investment in the plants through a non-cash charge to expense. Such an impairment could have a material adverse impact on Exelon’s results of operations.

Exelon and ComEd had approximately $2.6 billion of goodwill recorded at December 31, 2012 in connection with the merger between PECO and Unicom Corporation, the former parent company of ComEd. Under GAAP, goodwill remains 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. A successful IRS challenge to Exelon’s and ComEd’s like-kind exchange income tax position, adverse regulatory actions such as early termination of EIMA, or changes in significant assumptions used in estimating ComEd’s fair value (e.g., discount and growth rates, utility sector market performance and transactions, operating and capital expenditure requirements and the fair value of debt) could result in an impairment. Such an impairment would result in a non-cash charge to expense, which could have a material adverse impact on Exelon’s and ComEd’s results of operations.

See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Critical Accounting Policies and Estimates and Notes 6 and 8 of the Combined Notes to the Consolidated Financial Statements for additional discussion on long-lived asset and goodwill impairments.

The Registrants’ businesses are capital intensive, and their assets may require significant expenditures to maintain and are subject to operational failure, which could result in potential liability. (Exelon, Generation, ComEd, PECO and BGE)

The Registrants’ businesses are capital intensive and require significant investments by Generation in energy generation and by ComEd, PECO and BGE in transmission and distribution infrastructure projects. These operational systems and infrastructure have been in service for many years. Older equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and may require significant expenditures to operate efficiently. The Registrants’ results of operations, financial condition, or cash flows could be adversely affected if they were unable to effectively manage their capital

projects or raise the necessary capital. Furthermore, operational failure could result in potential liability if such failure results in damage to property or injury to individuals. See ITEM 1. BUSINESS 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 by third parties. In addition, the Registrants have rights under agreements which obligate third parties to indemnify the Registrants for various obligations, and the Registrants may incur substantial costs in the event that the applicable Registrant is unable to enforce those agreements or the applicable third party is otherwise unable to perform. (Exelon, Generation, ComEd, PECO and BGE)

The Registrants have issued guarantees of the performance of third parties, which obligate one or more of the Registrants or their subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by those 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.

The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are impacted by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations, which could impact that Registrant’s results of operations, cash flows and financial position. In connection with Exelon’s 2001 corporate restructuring, Generation assumed certain of ComEd’s and PECO’s rights and obligations with respect to their former generation businesses. Further, ComEd and PECO may have entered into agreements with third parties under which the third party agreed to indemnify ComEd or PECO for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third party or Generation experienced events that reduced its creditworthiness or the indemnity arrangement was unenforceable, ComEd or PECO could be liable for any existing or future claims, which could impact ComEd’s or PECO’s results of operations, cash flows and financial position.

Due to its significant contractual agreements with ComEd, PECO and BGE, Generation will be negatively affected in the event of non-performance or change in the creditworthiness of ComEd, PECO or BGE. (Exelon and Generation)

Generation currently provides power under procurement contracts with ComEd, PECO and BGE for a significant portion of their electricity supply requirements. 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, PECO’s, and BGE’s continued payments under these contracts and would be adversely affected by negative events impacting these contracts, including the non-performance or a significant change in the creditworthiness of ComEd, PECO or BGE. A default by ComEd, PECO or BGE under these contracts 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 where Generation serves load can switch from their respective energy delivery company 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 an electric distribution company’s 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 retail customers switching to or from competitive electric generation suppliers. If fewer of such customers switch from its retail load serving counterparties than Generation anticipates, the 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 customers from its retail load serving counterparties switch than Generation anticipates, the 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 regulatory and legislative actions. Fundamental changes in regulation or legislation or violation of tariffs or market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations and financial results. (Exelon, Generation, ComEd, PECO and BGE)

Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation. 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, PECO’s and BGE’s operating results and cash flows are heavily dependent on the ability of ComEd, PECO and BGE to recover their costs for the retail purchase and distribution of power to their customers. Similarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certain transactions. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxing authorities. Additionally, the Registrants should be cognizant of rules changes or Registrant actions that could result in potential violation of tariffs, market rules and anti-manipulation laws. Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations and could adversely affect their results of operations, cash flows and financial position.

Regulatory and legislative developments related to climate change and RPS may also significantly affect Exelon’s and Generation’s results of operations, cash flows and financial positions. Various legislative and regulatory proposals to address climate change through GHG emission reductions, if enacted, 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 a region, including Generation, may sell their output, thereby increasing the revenue Generation could realize from its low-carbon nuclear assets. However, national regulation or legislation addressing climate change through an 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 might derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future. Current state level climate change and renewable regulation is already providing incentives for regional wind development. 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 or state 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, or are themselves raising concerns, that energy prices in wholesale markets are too high or insufficient generation is being built because the competitive model is not working, and, therefore, are considering some form of re-regulation or some other means of reducing wholesale market prices or subsidizing new generation. Generation is dependent on robust and competitive wholesale energy markets to achieve its business objectives.

Approximately 60% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area 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 preservation of competitive wholesale power markets, such as PJM’s, and (2) the absence of material changes to market structures that would limit or otherwise negatively affect market competitiveness. Generation could also be adversely affected by state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize new generation, such as the New Jersey Capacity Legislation and the MDPSC’s RFP for new gas-fired generation in Maryland. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to the New Jersey Capacity Legislation and the Maryland new electric generation requirements.

In addition, FERC’s application of its Order 697 and its subsequent revisions could pose a risk that Generation will have difficulty satisfying FERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s authority to sell at market-based rates and none denying that authority. Generation’s most recent submission seeking reauthorization to sell at market-based rates was accepted by FERC on June 22, 2011 for the PJM region.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) was enacted into law on July 21, 2010. Its primary objective is to eliminate from the financial system the systemic risk that Congress believed was in part the cause of the financial crisis that unfolded during 2008. Dodd-Frank ushers in a brand new regulatory regime applicable to the over-the-counter (OTC) market for swaps. Generation relies on the OTC swaps markets as part of its program to hedge the price risk associated with its generation portfolio. In April 2012, the CFTC issued its rule defining swap dealers and major swap participants. Generation has determined that it will conduct its commercial hedging business as an end user in a manner that does not require registration as a swap dealer or major swap participant.

Notwithstanding the foregoing, Generation will still face additional regulatory obligations under Dodd-Frank, including some reporting requirements, clearing some additional transactions that it would otherwise enter into over-the-counter, and having to adhere to position limits. More fundamentally, however, the total burden that the rules could impose on all market participants could cause liquidity in the bilateral OTC swaps market to decrease substantially. Dodd-Frank may require up to $1 billion of additional collateral requirements at Generation, to be met with cash rather than letters of credit in a price stressed environment. Generation continues to monitor the rulemaking procedures and cannot predict the ultimate outcome that the financial reform legislation will have on its results of operations, cash flows or financial position.

Generation’s affiliation with ComEd, PECO and BGE, together with the presence of a substantial percentage of Generation’s physical asset base within the ComEd, PECO and BGE service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding ComEd, PECO and/or BGE 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, PECO and BGE 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, PECO and BGE 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, PECO or BGE, including transactions between Generation, on the one hand, and ComEd, PECO or BGE, 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.

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

The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions and solid waste disposal. 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 for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies are 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 Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. Pursuant to discussions with the NJDEP regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease generation operations at Oyster Creek by December 31, 2019, ten years before the expiration of its operating license in 2029.

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 19 of the Combined Notes to Consolidated Financial Statements for additional information.

Changes in ComEd’s, PECO’s and BGE’s respective 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, PECO and BGE)

ComEd, PECO and BGE 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, PECO or BGE 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 recovery mechanisms for costs associated with the procurement of electricity or gas, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.

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

ComEd, PECO and BGE cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania, Maryland or Federal regulators in 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, PECO and BGE will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant POLR and default service obligations to provide electricity and natural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of ComEd, PECO and BGE, as applicable, to recover their costs and could have a material adverse effect on ComEd’s, PECO’s and BGE’s results of operations, cash flows and financial position. See Note 3 of the Combined Notes to the Consolidated Financial Statements for information on the recently enacted EIMA and appeals in connection with ComEd’s 2007 and 2010 Illinois electric distribution rate cases.

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, PECO and BGE. (Exelon, Generation, ComEd, PECO and BGE)

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 Generation, ComEd, PECO and BGE, especially if timely cost recovery is not allowed. The impact could include increased costs for RECs and purchased power and increased rates for customers.

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, have increased capital expenditures and could significantly impact ComEd, PECO and BGE, 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.”

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

As of December 31, 2012, Exelon, ComEd, PECO and BGE have concluded that the operations of ComEd, PECO and BGE 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, PECO and BGE are required to eliminate the financial statement effects of regulation for that part of their business. That action 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, PECO and BGE. At December 31, 2012, the extraordinary gain could have been as much as $2.3 billion (before taxes) as a result of the elimination of ComEd’s regulatory assets and liabilities. At December 31, 2012, the extraordinary charge could have been as much as $703 million (before taxes) as a result of the elimination of PECO’s regulatory assets and liabilities. At December 31, 2012, the extraordinary charge could have been as much as $ 471 million (before taxes) as a result of the elimination of BGE’s regulatory assets and liabilities. Exelon would record the same amount of extraordinary gain or charge related to ComEd’s, PECO’s and BGE’s regulatory assets and liabilities. Further, Exelon would record a charge against OCI (before taxes) of up to $3.3 billion, $43 million and $682 million for ComEd, PECO and BGE, 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 at ComEd discussed above. A significant decrease in equity as a result of any changes could limit the ability of ComEd, PECO and BGE to pay dividends under Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in future results of operations. See Notes 1, 3 and 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’s goodwill, respectively.

Exelon and Generation may incur material costs of compliance if Federal and/or state regulation or 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. In 2009, select Northeast and Mid-Atlantic states implemented a model rule, developed via the RGGI, to regulate CO₂ emissions from fossil-fired generation. RGGI states are working on updated programs to further limit emissions and the EPA has introduced regulation to address greenhouse gases from new fossil plants that could potentially impact existing plants. If carbon reduction regulation or legislation becomes effective, Exelon and Generation may incur costs either to limit further 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 ITEM 1. BUSINESS “Global Climate Change” and Note 19 of the Combined Notes to Consolidated Financial Statements.

The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of ComEd, PECO, and BGE to the results of PJM’s RTEP and NERC compliance requirements. (Exelon, Generation, ComEd, PECO and BGE)

As a result of the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including Generation, ComEd, PECO and BGE, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. As operators of natural gas distribution systems, PECO and BGE are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are 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, PAPUC and MDPSC impose certain distribution reliability standards on ComEd, PECO and BGE, 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. Additionally, in 2011, the State of Maryland enacted legislation that imposed reliability and quality of service standards on electric companies and required the MDPSC to enact regulations during 2012 to implement these standards. These regulations could have a material impact on BGE’s financial results of operations, cash flows and financial position.

ComEd, PECO and BGE as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments may require ComEd, PECO and BGE to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. Uncertainties exist as to the construction of new transmission facilities, their cost and how those costs will be allocated to transmission system participants and customers. 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.

See Notes 3 and 19 of the Combined Notes to Consolidated Financial Statements for additional information.

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, PECO and BGE)

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 19 of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures that could have a material adverse effect on the Registrants’ results of operations.

Generation may be negatively affected by possible Nuclear Regulatory Commission actions that could affect the operations and profitability of its nuclear generating fleet. (Exelon and Generation)

Regulatory risk. 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.

As an example, prior to the Fukushima Daiichi accident on March 11, 2011, the NRC had been evaluating seismic risk. After the Fukushima Daiichi accident, the NRC’s focus on seismic risk intensified. As part of the NRC Near-Term Task Force (Task Force) review and evaluation of the Fukushima Daiichi accident, the Task Force recommended that plant operators conduct seismic reevaluations. In January 2012, the NRC released an updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the Task Force. These reevaluations could result in the required implementation of additional mitigation strategies or modifications. Additionally, the Task Force provided recommendations for future regulatory action by the NRC to be taken in the near and longer term. In response, the NRC issued three immediately effective orders (Tier 1) to commercial reactor licensees operating in the United States for compliance no later than December 31, 2016. The NRC is currently evaluating the remaining Task Force recommendations and has not taken action with respect to the Tier 2 and Tier 3 recommendations. Actions to comply with the Task Force recommendations may result in increased costs and significantly impact Generation’s results of operations or financial position. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Exelon Corporation, Executive Overview for a more detailed discussion of the Task Force Recommendations.

Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, such as the one previously considered at 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. The NRC’s temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants. In June 2012, the United States District Court of Appeals for the DC Circuit vacated the NRC’s temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. In September 2012, the NRC directed NRC Staff to complete a generic environmental impact statement and to revise the temporary storage rule through rulemaking no later than September 6, 2014.

Any regulatory action relating to the timing and availability of a repository for SNF may adversely affect Generation’s ability to decommission fully its nuclear units. Furthermore, under its contract with the DOE, Generation would be required to pay the DOE a one-time SNF storage fee including interest of approximately $1 billion as of December 31, 2012, prior to the first delivery of SNF. Generation currently estimates 2025 to be the earliest date when the DOE will begin accepting SNF, which could be delayed by further regulatory action. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information on the spent nuclear fuel obligation.

License renewals. Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of any renewed license period. 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.

As discussed above, in June 2012, the United States District Court of Appeals for the DC Circuit vacated the NRC’s temporary storage rule. Generation does not expect the NRC to issue license renewals until September 2014, at the earliest.

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, PECO and BGE)

Employees and contractors throughout the organization work in, and customers and the general public may be exposed to, potentially dangerous environments near their 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.

Natural disasters, war, acts and threats of terrorism, 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, PECO and BGE)

Generation’s fleet of nuclear and fossil-fueled power plants and ComEd’s, PECO’s and BGE’s distribution and transmission infrastructures could be impacted by natural disasters, such as seismic activity, more frequent and more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. 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. Examples of such events include the June 2012 “Derecho” storm, which interrupted electric service delivery to customers in BGE’s service territory, and the October 2012 category 1 hurricane, Hurricane Sandy, which interrupted electric service delivery to customers in PECO’s and BGE’s service territories and resulted in significant costs to PECO and BGE for restoration efforts. Other events include the 9.0 magnitude earthquake and ensuing tsunami experienced by Japan on March 11, 2011, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co., and the 5.8 magnitude earthquake and flooding associated with Hurricane Irene and Tropical Storm Lee that the Mid-Atlantic region of the United States experienced in 2011. These events increase the risk to Generation that the NRC or other regulatory or legislative bodies may change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological aspects. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units. Additionally, natural disasters and other events that have an adverse effect on the economy in general may adversely affect the Registrants’ operations and their ability to raise capital.

Exelon does not know the impact that potential terrorist attacks could have on the industry in general and on Exelon in particular. As owner-operators of infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities,

the Registrants face a risk that their operations would be direct targets of, or indirect casualties of, an act of terror. Any retaliatory military strikes or sustained military campaign may affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cyber security of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also may result in a decline in energy consumption, which may adversely affect the Registrants’ 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 Registrants would be significantly affected by the outbreak of a 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.

In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property and casualty losses subject to unforeseen occurrences or catastrophic events that may damage or destroy assets or interrupt operations.

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 committed third-party sales, including ComEd, PECO and BGE. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.

Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. 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.

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.

Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power

expense to meet supply commitments. In addition, Generation may not achieve the anticipated results under its series of planned power uprates across its nuclear fleet. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners. For plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, 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 generating plants or failure of transmission lines, could affect 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 or operated by Generation or owned by others, may exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect on Generation’s results of operations or financial position. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, 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. 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 previous years, NEIL had made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional discussion of nuclear insurance.

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 two 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 certain 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 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 would be 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 and Exelon’s and Generation’s results of operations and financial position could be significantly affected. See Note 3 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 making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met. As a result, Generation’s cash flows and financial position may be significantly adversely affected. See Note 13 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)

FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. 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 licenses 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, PECO’s and BGE’s operating costs, and customers’ and regulators’ opinions of ComEd, PECO and BGE, respectively, are affected by their ability to maintain the availability and reliability of their delivery and operational systems. (Exelon, ComEd, PECO and BGE)

Failures of the equipment or facilities, including information systems, used in ComEd’s, PECO’s and BGE’s delivery systems can interrupt the electric transmission and electric and natural gas delivery, which could negatively impact related revenues, and increase maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure, smart grid or other technologies in ComEd’s, PECO’s or BGE’s service territory fail to perform as intended or are not successfully integrated with billing and other information systems, ComEd’s, PECO’s and BGE’s financial condition, results of operations, and cash flows could be adversely affected. Furthermore, if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, ComEd’s, PECO’s or BGE’s financial results could be adversely affected. If an employee causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating the operational systems, ComEd’s, PECO’s or BGE’s

financial results could also be adversely affected. In addition, dependence upon automated systems may further increase the risk that operational system flaws or employee tampering or manipulation of those systems will result in losses that are difficult to detect.

The aforementioned failures or those of other utilities, including prolonged or repeated failures, can affect customer satisfaction and the level of regulatory oversight and ComEd’s, PECO’s and BGE’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, and those damages could be material to ComEd’s results of operations and cash flows.

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

Demand for electricity within ComEd’s, PECO’s and BGE’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. Also, insufficient availability of electric supply to meet customer demand could jeopardize ComEd’s, PECO’s and BGE’s ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring ComEd, PECO and BGE 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, PECO and BGE)

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 arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission and distribution operations. 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 physical and information security risks. (Exelon, Generation, ComEd, PECO and BGE)

The Registrants face physical and information security risks as the owner-operators of generation, transmission and distribution facilities. A security breach of the Registrants’ physical assets or information systems could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or subject the Registrants to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer data. If a significant breach occurred, the reputation of Exelon and its customer supply activities may be adversely affected, customer confidence may be diminished, or Exelon and its subsidiaries may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations. ComEd’s, PECO’s and BGE’s deployment of smart meters throughout their service territories may increase the risk of damage from an intentional disruption of the system by third parties. As a requirement of their SGIG grant, the DOE approved PECO’s and BGE’s cyber security plan related to its smart meter deployment and will review the plan annually through the expiration of the grant. As

with most companies in today’s environment, Exelon experiences attempts by hackers to infiltrate its corporate network. To date there have been no infiltrations that have resulted in loss of data or any significant effects on business operations. Exelon utilizes a dedicated team of cyber security professionals to ensure the protection of its information and ability to conduct business operations. Despite the measures taken by the Registrants to prevent a security breach, the Registrants cannot accurately assess the probability that a security breach may occur and are unable to quantify the potential impact of such an event. In addition, new or updated security regulations could require changes in current measures taken by the Registrants or their business operations and could adversely affect their results of operations, cash flows and financial position.

The Registrants may make investments in new business initiatives, including initiatives mandated by regulators, and markets that may not be successful, and acquisitions may not achieve the intended financial results. (Exelon, Generation, ComEd, PECO and BGE)

Generation continuously looks to invest in new business initiatives and actively participate in new markets. These include, but are not limited to, unconventional oil and gas exploration and production, residential power and gas sales, solar and wind generation, and managed load response. Such initiatives may involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. As these markets mature, there may be new market entrants or expansion by established competitors that increase competition for customers and resources. Additionally, it is possible that FERC, state public utility commissions or others may impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment. ComEd, PECO and BGE face risks associated with the Smart Grid mandated regulatory initiative. These risks include, but are not limited to, cost recovery, regulatory concerns, cyber security and obsolescence of technology. Due to these risks, no assurance can be given that such initiatives will be successful and will not have a material adverse effect on ComEd’s, PECO’s or BGE’s financial results.

Risks Related to the Merger

The merger may not achieve its anticipated results, and Exelon may be unable to integrate the operations of Constellation in the manner expected.

Exelon and Constellation entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and Constellation can be integrated in an efficient, effective and timely manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of Exelon’s businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies, valuation models, and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. Exelon may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect Exelon’s future business, financial condition, operating results and prospects.

The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.

Exelon currently anticipates that the merger will be accretive to earnings per share in 2013, which will be the first full year following completion of the merger. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.

The merger may adversely affect Exelon’s ability to attract and retain key employees.

Current and prospective Exelon employees may experience uncertainty about their future roles at Exelon as a result of the merger. In addition, current and prospective Exelon employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect Exelon’s ability to attract and retain key management and other personnel.

Exelon may incur unexpected transaction fees and merger-related costs in connection with the merger.

Exelon has incurred and expects to further incur a number of non-recurring expenses related to combining the operations of the Exelon and Constellation. Exelon may incur additional unanticipated costs in the integration of the businesses of the two companies. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.

Exelon may encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements associated with regulatory approvals for the Constellation merger.

As a result of the process to obtain regulatory approvals required for the Constellation merger, Exelon is committed to various programs, contributions, investments and market mitigation measures in several settlement agreements and regulatory approval orders. It is possible that Exelon may encounter delays, unexpected difficulties or costs in meeting these commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could adversely affect Exelon’s financial position and operating results.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

Exelon, Generation, ComEd, PECO and BGE

None.

ITEM 2.

PROPERTIES

Generation

The following table describes Generation’s interests in net electric generating capacity by station at December 31, 2012:

Station

Region

Location

No. of
Units

Percent
Owned ^(a)

Primary
Fuel Type

Primary
Dispatch
Type ^(b)

Net
Generation
Capacity (MW) ^(c)

Limerick

Mid-Atlantic

Limerick Twp., PA

Uranium

Base-load

2,314

Peach Bottom

Mid-Atlantic

Peach Bottom Twp., PA

Uranium

Base-load

1,158

^(f)

Salem

Mid-Atlantic

Hancock’s Bridge, NJ

42.59

Uranium

Base-load

1,006

^(f)

Calvert Cliffs

Mid-Atlantic

Calvert Co., MD

50.01

Uranium

Base-load

877

^(f)^(h)

Three Mile Island

Mid-Atlantic

Londonderry Twp, PA

Uranium

Base-load

837

Keystone

Mid-Atlantic

Shelocta, PA

41.98

Coal

Base-load

714

^(f)

Oyster Creek

Mid-Atlantic

Forked River, NJ

Uranium

Base-load

625

^(e)

Conowingo

Mid-Atlantic

Harford Co., MD

Hydroelectric

Base-load

572

Conemaugh

Mid-Atlantic

New Florence, PA

31.28

Coal

Base-load

531

^(f)

Criterion

Mid-Atlantic

Oakland, MD

Wind

Base-load

Colver

Mid-Atlantic

Colver Twp., PA

Waste Coal

Base-load

^(f)

Solar Horizons

Mid-Atlantic

Various

Solar

Base-load

Solar New Jersey 2

Mid-Atlantic

Various

Solar

Base-load

Solar New Jersey 1

Mid-Atlantic

Various

Solar

Base-load

Solar Maryland

Mid-Atlantic

Various

Solar

Base-load

Solar Federal

Mid-Atlantic

Various

Solar

Base-load

Solar New Jersey 3

Mid-Atlantic

Various

Solar

Base-load

Muddy Run

Mid-Atlantic

Lancaster, PA

Hydroelectric

Intermediate

1,070

Eddystone 3, 4

Mid-Atlantic

Eddystone, PA

Oil/Gas

Intermediate

760

Safe Harbor

Mid-Atlantic

Safe Harbor, PA

66.7

Hydroelectric

Intermediate

277

^(f)

Croydon

Mid-Atlantic

Bristol Twp., PA

Oil

Peaking

391

Perryman

Mid-Atlantic

Hartford Co., MD

Oil/Gas

Peaking

347

Handsome Lake

Mid-Atlantic

Rockland Twp., PA

Gas

Peaking

268

Riverside

Mid-Atlantic

Baltimore Co., MD

Oil/Gas

Peaking

228

Westport

Mid-Atlantic

Baltimore Co., MD

Gas

Peaking

116

Notch Cliff

Mid-Atlantic

Baltimore, MD

Gas

Peaking

101

Richmond

Mid-Atlantic

Philadelphia, PA

Oil

Peaking

Gould Street

Mid-Atlantic

Baltimore, MD

Gas

Peaking

Philadelphia Road

Mid-Atlantic

Baltimore Co., MD

Oil

Peaking

Eddystone

Mid-Atlantic

Eddystone, PA

Oil

Peaking

Fairless Hills

Mid-Atlantic

Falls Twp, PA

Landfill Gas

Peaking

Delaware

Mid-Atlantic

Philadelphia, PA

Oil

Peaking

Southwark

Mid-Atlantic

Philadelphia, PA

Oil

Peaking

Falls

Mid-Atlantic

Falls Twp., PA

Oil

Peaking

Moser

Mid-Atlantic

Lower Pottsgrove Twp., PA

Oil

Peaking

Chester

Mid-Atlantic

Chester, PA

Oil

Peaking

Salem

Mid-Atlantic

Hancock’s Bridge, NJ

42.59

Oil

Peaking

^(f)

Pennsbury

Mid-Atlantic

Falls Twp., PA

Landfill Gas

Peaking

Keystone

Mid-Atlantic

Shelocta, PA

41.98

Oil

Peaking

^(f)

Conemaugh

Mid-Atlantic

New Florence, PA

31.28

Oil

Peaking

^(f)

Total Mid-Atlantic

12,993

Braidwood

Midwest

Braidwood, IL

Uranium

Base-load

2,349

LaSalle

Midwest

Seneca, IL

Uranium

Base-load

2,327

Byron

Midwest

Byron, IL

Uranium

Base-load

2,326

Dresden

Midwest

Morris, IL

Uranium

Base-load

1,790

Quad Cities

Midwest

Cordova, IL

Uranium

Base-load

1,403

^(f)

Station

Region

Location

No. of
Units

Percent
Owned ^(a)

Primary
Fuel Type

Primary
Dispatch
Type ^(b)

Net
Generation
Capacity (MW) ^(c)

Clinton

Midwest

Clinton, IL

Uranium

Base-load

1,067

Michigan Wind 2

Midwest

Bingham Twp., MI

Wind

Base-load

Beebe

Midwest

Gratiot Co., MI

Wind

Base-load

Michigan Wind 1

Midwest

Bingham Twp., MI

Wind

Base-load

Harvest 2

Midwest

Huron Co., MI

Wind

Base-load

Harvest

Midwest

Huron Co., MI

Wind

Base-load

Wildcat

Midwest

Lee Co., NM

Wind

Base-load

Ewington

Midwest

Jackson Co., MN

Wind

Base-load

^(f)

Marshall

Midwest

Lyon Co., MN

98-99

Wind

Base-load

^(f)

City Solar

Midwest

Chicago, IL

Solar

Base-load

Norgaard

Midwest

Lincoln Co., MN

Wind

Base-load

^(f)

AgriWind

Midwest

Bureau Co., IL

Wind

Base-load

^(f)

Cisco

Midwest

Jackson Co., MN

Wind

Base-load

^(f)

Brewster

Midwest

Jackson Co., MN

94-99

Wind

Base-load

^(f)

Wolf

Midwest

Nobles Co., MN

Wind

Base-load

^(f)

CP Windfarm

Midwest

Faribault Co., MN

Wind

Base-load

Moore

Midwest

Faribault Co., MN

Wind

Base-load

Cowell

Midwest

Pipestone Co., MN

Wind

Base-load

^(f)

Solar Ohio

Midwest

Various

Solar

Base-load

Southeast Chicago

Midwest

Chicago, IL

Gas

Peaking

296

Total Midwest

12,034

Wolf Hollow 1, 2, 3

ERCOT

Granbury, TX

Gas

Intermediate

705

Mountain Creek 8

ERCOT

Dallas, TX

Gas

Intermediate

565

Colorado Bend

ERCOT

Wharton, TX

Gas

Intermediate

498

Quail Run

ERCOT

Odessa, TX

Gas

Intermediate

488

Handley 3

ERCOT

Fort Worth, TX

Gas

Intermediate

395

Handley 4, 5

ERCOT

Fort Worth, TX

Gas

Peaking

870

Mountain Creek 6, 7

ERCOT

Dallas, TX

Gas

Peaking

240

LaPorte

ERCOT

Laporte, TX

Gas

Peaking

152

Total ERCOT

3,913

Holyoke Solar

New England

Various

Solar

Base-load

Solar Massachusetts

New England

Various

Solar

Base-load

Solar Net Metering

New England

Various

Solar

Base-load

Solar Connecticut

New England

Various

Solar

Base-load

Mystic 8, 9

New England

Charlestown, MA

Gas

Intermediate

1,382

Fore River

New England

North Weymouth, MA

Gas

Intermediate

688

Mystic 7

New England

Charlestown, MA

Oil/Gas

Intermediate

560

Wyman

New England

Yarmouth, ME

5.89

Oil

Intermediate

^(f)

Medway

New England

West Medway, MA

Oil/Gas

Peaking

105

Framingham

New England

Framingham, MA

Oil

Peaking

New Boston

New England

South Boston, MA

Oil

Peaking

Mystic Jet

New England

Charlestown, MA

Oil

Peaking

Total New England

2,832

Nine Mile Point

New York

Scriba, NY

50.01

Uranium

Base-load

798

^(f)^(h)

Ginna

New York

Ontario, NY

50.01

Uranium

Base-load

288

^(f)^(h)

Total New York

1,086

Shooting Star

Other

Kiowa Co., KS

Wind

Base-load

104

Whitetail

Other

Webb Co., TX

Wind

Base-load

Exelon Wind 4

Other

Hansford Co., TX

Wind

Base-load

Bluegrass Ridge

Other

Gentry Co., MO

Wind

Base-load

Station

Region

Location

No. of
Units

Percent
Owned ^(a)

Primary
Fuel Type

Primary
Dispatch
Type ^(b)

Net
Generation
Capacity (MW) ^(c)

Conception

Other

Nodaway Co., MO

Wind

Base-load

Cow Branch

Other

Atchinson Co., MO

Wind

Base-load

Mountain Home

Other

Elmore Co., ID

Wind

Base-load

High Mesa

Other

Elmore Co., ID

Wind

Base-load

Echo 1

Other

Umatilla Co., OR

Wind

Base-load

^(f)

AVSR

Other

Los Angeles County, CA

Solar

Base-load

^(g)

Sacramento PV Energy

Other

Various

Solar

Base-load

Cassia

Other

Twin Falls Co., ID

Wind

Base-load

Sunnyside

Other

Sunnyside, UT

Waste Coal

Base-load

^(f)

Echo 2

Other

Morrow Co., OR

Wind

Base-load

Tuana Springs

Other

Twin Falls Co., ID

Wind

Base-load

Greensburg

Other

Kiowa Co., KS

Wind

Base-load

Echo 3

Other

Morrow Co., OR

Wind

Base-load

^(f)

Exelon Wind 1

Other

Hansford Co., TX

Wind

Base-load

Exelon Wind 2

Other

Hansford Co., TX

Wind

Base-load

Exelon Wind 3

Other

Hansford Co., TX

Wind

Base-load

Exelon Wind 5

Other

Sherman Co., TX

Wind

Base-load

Exelon Wind 6

Other

Sherman Co., TX

Wind

Base-load

Exelon Wind 7

Other

Moore Co., TX

Wind

Base-load

Exelon Wind 8

Other

Moore Co., TX

Wind

Base-load

Exelon Wind 9

Other

Moore Co., TX

Wind

Base-load

Exelon Wind 10

Other

Moore Co., TX

Wind

Base-load

Exelon Wind 11

Other

Moore Co., TX

Wind

Base-load

High Plains

Other

Moore Co., TX

99.5

Wind

Base-load

^(f)

Threemile Canyon

Other

Morrow Co., OR

Wind

Base-load

Solar Arizona

Other

Various

Solar

Base-load

Outback Solar

Other

Various

Solar

Base-load

Loess Hills

Other

Atchinson Co., MO

Wind

Base-load

Denver Airport Solar

Other

Various

Solar

Base-load

Solar California

Other

Various

Solar

Base-load

Hillabee

Other

Alexander City, AL

Gas

Intermediate

684

Malacha

Other

Muck Valley, CA

Hydroelectric

Intermediate

^(f)

West Valley

Other

Salt Lake City, UT

Gas

Peaking

200

Grand Prairie

Other

Alberta, Canada

Gas

Peaking

SEGS 4, 5, 6

Other

Kramer Junction, CA

4.2-12.2

Solar

Peaking

^(f)

Total Other

1,873

Total

34,731

(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 and diesels normally used during the maximum load periods.

(c)	For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity.

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

(e)	Generation has agreed to permanently cease generation operation at Oyster Creek by December 31, 2019.

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

(g)	Expected capacity upon project completion is 230MW. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

(h)	Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. Generation also has a unit contingent PPA with CENG under which it purchases 85 to 90% of the output of CENG’s nuclear generating facilities that is not sold to third parties under the pre-existing PPAs through 2014.

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 or 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, 2012 were as follows:


Voltage (Volts)		Circuit Miles
765,000		90
345,000		2,642
138,000		2,237

ComEd’s electric distribution system includes 35,563 circuit miles of overhead lines and 30,506 circuit 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 significant portion of its transmission lines 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 high voltage electric transmission lines owned and in service at December 31, 2012 were as follows:


Voltage (Volts)		Circuit Miles
500,000		188^(a)
230,000		548
138,000		156
69,000		200

(a)	In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey.

PECO’s electric distribution system includes 13,013 circuit miles of overhead lines and 8,901 circuit miles of underground lines.

Gas

The following table sets forth PECO’s natural gas pipeline miles at December 31, 2012:


	Pipeline Miles
Transmission		31
Distribution		6,747
Service piping		6,038

Total		12,816

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 31 natural gas city gate stations and direct pipeline customer delivery points 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.

BGE

BGE’s electric substations and a significant portion of its transmission lines are located on property that BGE 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. BGE 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

BGE’s high voltage electric transmission lines owned and in service at December 31, 2012 were as follows:


Voltage (Volts)		Circuit Miles
500,000		218
230,000		321
138,000		54
115,000		697

BGE’s electric distribution system includes 9,411 circuit miles of overhead lines and 15,748 circuit miles of underground lines.

Gas

The following table sets forth BGE’s natural gas pipeline miles at December 31, 2012:


	Pipeline Miles
Transmission		164
Distribution		7,015
Service piping		6,146

Total		13,325

BGE has an LNG facility located in Baltimore, Maryland that has a storage capacity of 1,000 mmcf and a send-out capacity of 298 mmcf/day, an LNG facility located in Westminster, Maryland that has a storage capacity of 5.8 mmcf and a send-out capacity of 5.8 mmcf/day, and a propane-air plant located in Baltimore, Maryland, with a storage capacity of 500 mmcf and a send-out capacity of 81 mmcf/day.

Property Insurance

BGE owns its principal headquarters building located in downtown Baltimore. BGE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, BGE 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 BGE.

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, PECO and BGE

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 3 and 19 of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

ITEM 4.

MINE SAFETY DISCLOSURES

Exelon, Generation, ComEd, PECO and BGE

Not Applicable to the Registrants.

PART II

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

ITEM 5.

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

Exelon

Exelon’s common stock is listed on the New York Stock Exchange. As of January 31, 2013, there were 855,019,272 shares of common stock outstanding and approximately 134,194 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:


	2012								2011
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	37.50	$	39.82	$	39.37	$	43.70	$	45.45	$	45.27	$	42.89	$	43.58
Low price		28.40		34.54		36.27		38.31		39.93		39.51		39.53		39.06
Close		29.74		35.58		37.62		39.21		43.37		42.61		42.84		41.24
Dividends		0.525		0.525		0.525		0.525		0.525		0.525		0.525		0.525

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 common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index for the period 2008 through 2012.

This performance chart assumes:

•

$100 invested on December 31, 2007 in Exelon 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 31, 2013, Exelon indirectly held the entire membership interest in Generation.

ComEd

As of January 31, 2013, there were 127,016,764 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2013, in addition to Exelon, there were 272 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

PECO

As of January 31, 2013, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.

BGE

As of January 31, 2013, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.

Exelon, Generation, ComEd, PECO and BGE

Dividends

Under applicable Federal law, Generation, ComEd, PECO and BGE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO or BGE 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 a financing arranged through ComEd Financing III that ComEd 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. No such event has occurred.

PECO’s Amended and Restated 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, 2012, such capital was $3 billion and amounted to about 34 times the liquidating value of the outstanding preferred securities of $87 million.

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO 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 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. No such event has occurred.

BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE’s preference stock have not been paid.

At December 31, 2012, Exelon had retained earnings of $9,893 million, including Generation’s undistributed earnings of $3,168 million, ComEd’s retained earnings of $721 million consisting of retained earnings appropriated for future dividends of $2,360 million, partially offset by $1,639 million of unappropriated retained deficits, PECO’s retained earnings of $593 million, and BGE’s retained earnings of $808 million.

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2012 and 2011:


	2012								2011
(per share)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter
Exelon	$	0.525	$	0.525	$	0.525	$	0.525	$	0.525	$	0.525	$	0.525	$	0.525

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


	2012								2011
(in millions)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter
Generation	$	242	$	493	$	291	$	600	$	111	$	61	$	—	$	—
ComEd		10		10		10		75		75		75		75		75
PECO		85		86		85		87		80		84		73		111
BGE		—		—		—		—		—		—		—		85	^(a)

(a)	Dividends on common stock for $85 million were paid to Constellation for the year ended December 31, 2011.

First Quarter 2013 Dividend. On February 6, 2013, the Exelon Board of Directors declared a first quarter 2013 regular quarterly dividend of $0.525 per share on Exelon’s common stock payable on March 8, 2013, to shareholders of record of Exelon at the end of the day on February 19, 2013.

Revised Dividend Policy. On February 6, 2013, the Exelon Board of Directors approved a revised dividend policy which contemplates a regular $0.31 per share quarterly dividend on Exelon’s common stock payable beginning in the second quarter of 2013 (or $1.24 per share on an annualized basis), subject to quarterly declarations by the Board of Directors. The second quarter 2013 quarterly dividend of $0.31 per share on Exelon’s common stock is expected to be approved by the Exelon Board of Directors in the second quarter of 2013.

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 ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


	For the Years Ended December 31,
(In millions, except per share data)	2012 ^(a)		2011		2010		2009		2008
Statement of Operations data:
Operating revenues	$	23,489	$	19,063	$	18,644	$	17,318	$	18,859
Operating income		2,380		4,479		4,726		4,750		5,299
Income from continuing operations		1,171		2,499		2,563		2,706		2,717
Income from discontinued operations		—		—		—		1		20
Net income		1,171		2,499		2,563		2,707		2,737
Earnings per average common share (diluted):
Income from continuing operations	$	1.42	$	3.75	$	3.87	$	4.09	$	4.10
Income from discontinued operations		—		—		—		—		0.03

Net income	$	1.42	$	3.75	$	3.87	$	4.09	$	4.13

Dividends per common share	$	2.10	$	2.10	$	2.10	$	2.10	$	2.03

Average shares of common stock outstanding—diluted		819		665		663		662		662

(a)	The 2012 financial results only include the operations of Constellation and BGE from the date of the merger with Constellation (the Merger), March 12, 2012, through December 31, 2012.


	December 31,
(In millions)	2012		2011		2010		2009		2008
Balance Sheet data:
Current assets	$	10,133	$	5,713	$	6,398	$	5,441	$	5,130
Property, plant and equipment, net		45,186		32,570		29,941		27,341		25,813
Noncurrent regulatory assets		6,497		4,518		4,140		4,872		5,940
Goodwill		2,625		2,625		2,625		2,625		2,625
Other deferred debits and other assets		14,113		9,569		9,136		8,901		8,038

Total assets	$	78,554	$	54,995	$	52,240	$	49,180	$	47,546

Current liabilities	$	7,784	$	5,134	$	4,240	$	4,238	$	3,811
Long-term debt, including long-term debt to financing trusts		18,346		12,189		12,004		11,385		12,592
Noncurrent regulatory liabilities		3,981		3,627		3,555		3,492		2,520
Other deferred credits and other liabilities		26,626		19,570		18,791		17,338		17,489
Preferred securities of subsidiary		87		87		87		87		87
Noncontrolling interest		106		3		3		—		—
BGE preference stock not subject to mandatory redemption		193		—		—		—		—
Shareholders’ equity		21,431		14,385		13,560		12,640		11,047

Total liabilities and shareholders’ equity	$	78,554	$	54,995	$	52,240	$	49,180	$	47,546

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 ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


	For the Years Ended December 31,
(In millions)	2012 ^(a)		2011		2010		2009		2008
Statement of Operations data:
Operating revenues	$	14,437	$	10,447	$	10,025	$	9,703	$	10,754
Operating income		1,120		2,875		3,046		3,295		3,994
Income from continuing operations		558		1,771		1,972		2,122		2,258
Income from discontinued operations		—		—		—		—		20
Net income		558		1,771		1,972		2,122		2,278

(a)	The 2012 financial results only include the operations of Constellation from the date of the merger with Constellation (the Merger), March 12, 2012, through December 31, 2012.


	December 31,
(In millions)	2012		2011		2010		2009		2008
Balance Sheet data:
Current assets	$	6,211	$	3,217	$	3,087	$	3,360	$	3,486
Property, plant and equipment, net		19,531		13,475		11,662		9,809		8,907
Other deferred debits and other assets		14,939		10,741		9,785		9,237		7,691

Total assets	$	40,681	$	27,433	$	24,534	$	22,406	$	20,084

Current liabilities	$	4,097	$	2,144	$	1,843	$	2,262	$	2,168
Long-term debt		7,455		3,674		3,676		2,967		2,502
Other deferred credits and other liabilities		16,464		12,907		11,838		10,385		8,848
Noncontrolling interest		108		5		5		2		1
Member’s equity		12,557		8,703		7,172		6,790		6,565

Total liabilities and member’s equity	$	40,681	$	27,433	$	24,534	$	22,406	$	20,084

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 ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


	For the Years Ended December 31,
(In millions)	2012		2011		2010		2009		2008
Statement of Operations data:
Operating revenues	$	5,443	$	6,056	$	6,204	$	5,774	$	6,136
Operating income		886		982		1,056		843		667
Net income		379		416		337		374		201


	December 31,
(In millions)	2012		2011		2010		2009		2008
Balance Sheet data:
Current assets	$	1,775	$	2,188	$	2,151	$	1,579	$	1,309
Property, plant and equipment, net		13,826		13,121		12,578		12,125		11,655
Goodwill		2,625		2,625		2,625		2,625		2,625
Noncurrent regulatory assets		666		699		947		1,096		858
Other deferred debits and other assets		4,013		4,005		3,351		3,272		2,790

Total assets	$	22,905	$	22,638	$	21,652	$	20,697	$	19,237

Current liabilities	$	1,655	$	2,071	$	2,134	$	1,597	$	1,153
Long-term debt, including long-term debt to financing trusts		5,521		5,421		4,860		4,704		4,915
Noncurrent regulatory liabilities		3,229		3,042		3,137		3,145		2,440
Other deferred credits and other liabilities		5,177		5,067		4,611		4,369		3,994
Shareholders’ equity		7,323		7,037		6,910		6,882		6,735

Total liabilities and shareholders’ equity	$	22,905	$	22,638	$	21,652	$	20,697	$	19,237

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 ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


	For the Years Ended December 31,
(In millions)	2012		2011		2010		2009		2008
Statement of Operations data:
Operating revenues	$	3,186	$	3,720	$	5,519	$	5,311	$	5,567
Operating income		623		655		661		697		699
Net income		381		389		324		353		325
Net income on common stock		377		385		320		349		321

	December 31,
(In millions)	2012		2011		2010		2009		2008
Balance Sheet data:
Current assets	$	1,094	$	1,243	$	1,670	$	1,006	$	819
Property, plant and equipment, net		6,078		5,874		5,620		5,297		5,074
Noncurrent regulatory assets		1,378		1,216		968		1,834		2,597
Other deferred debits and other assets		803		823		727		882		679

Total assets	$	9,353	$	9,156	$	8,985	$	9,019	$	9,169

Current liabilities	$	1,158	$	1,145	$	1,163	$	939	$	981
Long-term debt, including long-term debt to financing trusts		1,831		1,781		2,156		2,405		2,960
Noncurrent regulatory liabilities		538		585		418		317		49
Other deferred credits and other liabilities		2,757		2,620		2,278		2,706		2,910
Preferred securities		87		87		87		87		87
Shareholders’ equity		2,982		2,938		2,883		2,565		2,182

Total liabilities and shareholders’ equity	$	9,353	$	9,156	$	8,985	$	9,019	$	9,169

BGE

The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by reference to and should be read in conjunction with BGE’s Consolidated Financial Statements and ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


	For the Years Ended December 31,
(In millions)	2012			2011		2010		2009		2008
Statement of Operations data:
Operating revenues	$	2,735		$	3,068	$	3,541	$	3,646	$	3,769
Operating income		132			314		350		268		183
Net income		4			136		147		91		52
Net (loss) income on common stock		(9	)		123		134		78		39


	December 31,
(In millions)	2012		2011 ^(a)		2010 ^(a)		2009 ^(a)		2008 ^(a)
Balance Sheet data:
Current assets	$	973	$	969	$	1,012	$	1,205	$	1,093
Property, plant and equipment, net		5,498		5,132		4,754		4,470		4,290
Noncurrent regulatory assets		522		551		566		602		670
Other deferred debits and other assets		506		551		545		386		231

Total assets	$	7,499	$	7,203	$	6,877	$	6,663	$	6,284

Current liabilities	$	973	$	734	$	728	$	753	$	1,041
Long-term debt, including long-term debt to financing trusts and variable interest entities		1,969		2,186		2,060		2,141		2,198
Noncurrent regulatory liabilities		214		201		192		188		175
Other deferred credits and other liabilities		1,985		1,781		1,634		1,434		1,125
Preference stock not subject to mandatory redemption		190		190		190		190		190
Shareholders’ equity		2,168		2,111		2,073		1,939		1,538
Noncontrolling interest		—		—		—		18		17

Total liabilities and shareholders’ equity	$	7,499	$	7,203	$	6,877	$	6,663	$	6,284

(a)	BGE retrospectively reclassified certain regulatory assets and regulatory liabilities to conform to the current year presentation.

Item 7.

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

Exelon

Executive Overview

Exelon, a utility services holding company, operates through the following principal subsidiaries:

•

Generation, whose integrated business consists of owned, contracted and investments in electric generating facilities managed through customer supply of electric and natural gas products and services, including renewable energy products, risk management services and natural gas exploration and production activities.

•

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

•

BGE, whose business consists of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore.

Exelon has nine reportable segments consisting of Generation’s six power marketing reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and other regions in Generation), ComEd, PECO and BGE. See Note 21 of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s reportable segments.

Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating 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’s consolidated financial information includes the results of its four separate operating subsidiary registrants, Generation, ComEd, PECO and BGE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO and BGE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Financial Results. The following consolidated financial results reflect the results of Exelon for year ended December 31, 2012 compared to the same period in 2011. The 2012 financial results only include the operations of Constellation and BGE from the date of the merger with Constellation (the Merger), March 12, 2012, through December 31, 2012. All amounts presented below are before the impact of income taxes, except as noted.


	The Years Ended December 31,																					Favorable (Unfavorable) Variance
	2012																		2011
	Generation			ComEd			PECO			BGE			Other			Exelon			Exelon
Operating revenues	$	14,437		$	5,443		$	3,186		$	2,091		$	(1,668	)	$	23,489		$	19,063		$	4,426
Purchased power and fuel		7,061			2,307			1,375			1,052			(1,638	)		10,157			7,267			(2,890	)

Revenue net of purchased power and fuel ^(a)		7,376			3,136			1,811			1,039			(30	)		13,332			11,796			1,536

Other operating expenses
Operating and maintenance		5,028			1,345			809			596			183			7,961			5,184			(2,777	)
Depreciation and amortization		768			610			217			238			48			1,881			1,347			(534	)
Taxes other than income		369			295			162			167			26			1,019			785			(234	)

Total other operating expenses		6,165			2,250			1,188			1,001			257			10,861			7,316			(3,545	)
Equity in earnings of unconsolidated affiliates		(91	)		—			—			—			—			(91	)		(1	)		(90	)

Operating income		1,120			886			623			38			(287	)		2,380			4,479			(2,099	)

Other income and (deductions)
Interest expense, net		(301	)		(307	)		(123	)		(111	)		(86	)		(928	)		(726	)		(202	)
Other, net		239			39			8			19			41			346			203			143

Total other income and (deductions)		(62	)		(268	)		(115	)		(92	)		(45	)		(582	)		(523	)		(59	)

Income (loss) before income taxes		1,058			618			508			(54	)		(332	)		1,798			3,956			(2,158	)
Income taxes		500			239			127			(23	)		(216	)		627			1,457			830

Net income (loss)		558			379			381			(31	)		(116	)		1,171			2,499			(1,328	)

Net (loss) income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(4	)		—			4			11			—			11			4			(7	)

Net income (loss) on common stock	$	562		$	379		$	377		$	(42	)	$	(116	)	$	1,160		$	2,495		$	(1,335	)

(a)

The Registrants’ evaluate operating performance using the measure of revenue net of purchased power and fuel expense. The Registrants’ believe 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.

Exelon’s net income was $1,160 million for the year ended December 31, 2012 as compared to $2,495 million for the year ended December 31, 2011, and diluted earnings per average common share were $1.42 for the year ended December 31, 2012 as compared to $3.75 for the year ended December 31, 2011.

Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $1,536 million primarily due to the addition of Constellation’s and BGE’s financial results. BGE’s operating revenue net of purchased power and fuel expense was $1,039 million from March 12, 2012 to December 31, 2012, which included the $113 million impact of the residential customer rate credit in connection with the Merger. Generation’s operating revenue net of

purchased power and fuel expense increased by $518 million primarily due to the New England, New York, ERCOT and Other Regions. These regions contributed $729 million and did not previously have a significant impact on Generation’s revenue net of purchased power and fuel expense prior to the Merger. Generation’s results were also favorably affected by $588 million of other activities, including retail gas, energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities, and by $83 million in the Mid-Atlantic region also due to the addition of Constellation’s operations in 2012. Generation had mark-to-market gains of $515 million in 2012 from economic hedging activities, net of intercompany eliminations, compared to $288 million in mark-to-market losses in 2011. Offsetting these favorable impacts, Generation incurred $1,098 million of amortization expense for the acquired energy contracts, net, recorded at fair value at the merger date. Also, revenue net of purchased power and fuel expenses decreased by $549 million in the Midwest region due to lower capacity revenues, increased nuclear fuel costs and lower realized power prices.

ComEd’s operating revenues net of purchased power and fuel expense increased by $115 million primarily as a result of the annual reconciliation of ComEd’s distribution revenue requirement pursuant to EIMA, net of lower allowed return on equity, and increased transmission revenue. PECO’s operating revenues net of purchased power and fuel expense decreased by $45 million primarily as a result of unfavorable weather and a decline in electric load.

Operating and maintenance expense increased by $2,777 million primarily due to the addition of BGE and Constellation. In addition, Exelon’s results were unfavorably affected by the $272 million loss on the sale of three Maryland generating stations, of which $278 million was recorded to operating and maintenance expense. Including Constellation and BGE, labor, other benefits, contracting and materials increased by $1,393 million, pension and non-pension postretirement benefits expense increased by $199 million and Constellation merger and integration costs increased by $226 million. In addition, Exelon incurred $216 million in costs incurred as part of the Maryland order approving the Merger and costs of $195 million associated with a settlement with the FERC in March, 2012, and BGE incurred $71 million of storm costs.

Depreciation and amortization expense increased by $534 million primarily due to higher plant balances resulting from the addition of BGE’s and Constellation’s plant balances as well as ongoing capital expenditures across the operating companies.

Equity in losses of unconsolidated affiliates increased by $90 million primarily due to the amortization of the basis difference in CENG recorded at fair value at the merger date, partially offset by net income generated from Exelon’s equity investment in CENG.

Interest expense increased by $202 million due to an increase in debt obligations as a result of the Merger and an increase in debt issued at Generation and BGE in 2012. Offsetting these unfavorable impacts, interest expense at ComEd and PECO decreased due to a lower outstanding debt during 2012 and lower interest rates on long-term debt.

Exelon’s effective income tax rates for the years ended December 31, 2012 and 2011 were 34.9% and 36.8%, respectively. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

For further detail regarding the financial results for the years ended December 31, 2012 and 2011, including explanation of the non-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.

Adjusted (non-GAAP) Operating Earnings

Exelon’s adjusted (non-GAAP) operating earnings for the year ended December 31, 2012 were $2,330 million, or $2.85 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,763 million, or $4.16 per diluted share, for the same period in 2011. In addition to net income, Exelon evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings 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.

The following table provides a reconciliation between net income as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the year ended December 31, 2012 as compared to 2011:


	December 31,
	2012						2011
(All amounts after tax; in millions, except per share amounts)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income	$	1,160		$	1.42		$	2,495		$	3.75
Mark-to-Market Impact of Economic Hedging Activities ^(a)		(310	)		(0.38	)		174			0.27
Unrealized (Gains) Losses Related to NDT Fund Investments ^(b)		(56	)		(0.07	)		1			—
Plant Retirements and Divestitures ^(c)		236			0.29			33			0.05
Asset Retirement Obligation ^(d)		1			—			16			0.02
Constellation Merger and Integration Costs ^(e)		257			0.31			46			0.07
Other Acquisition Costs ^(f)		3			—			5			0.01
Wolf Hollow Acquisition ^(g)		—			—			(23	)		(0.03	)
Recovery of Costs Pursuant to ComEd Distribution Rate Case Order ^(h)		—			—			(17	)		(0.03	)
Non-Cash Remeasurement of Deferred Income Taxes ⁽ⁱ⁾		(117	)		(0.14	)		33			0.05
Amortization of Commodity Contract Intangibles ^(j)		758			0.93			—			—
Amortization of the Fair Value of Certain Debt ^(k)		(9	)		(0.01	)		—			—
Maryland Commitments ^(l)		227			0.28			—			—
FERC Settlement ^(m)		172			0.21			—			—
Midwest Generation Bankruptcy Charges ⁽ⁿ⁾		8			0.01			—			—

Adjusted (non-GAAP) Operating Earnings	$	2,330		$	2.85		$	2,763		$	4.16

(a)

Reflects the impact of (gains) losses for the years ended December 31, 2012 and 2011, respectively, on Generation’s economic hedging activities (net of taxes of $200 million and $114 million, respectively). See Note 10 of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities.

(b)

Reflects the impact of unrealized (gains) losses for the years ended December 31, 2012 and 2011, respectively, on Generation’s NDT fund investments for Non-Regulatory Agreement Units (net of taxes of $(132) million and $(3) million, respectively). See Note 13 of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

(c)

Primarily reflects the impact associated with the sale of three generating stations associated with certain of the regulatory approvals required for the merger for the year ended December 31, 2012 (net of taxes of $106 million). For December 31, 2012 and 2011, also reflects incremental accelerated depreciation associated with the retirement of certain fossil generating

units and compensation for operating two of the units past their planned retirement date under a FERC-approved reliability-must-run rate schedule. See Note 15 of the Combined Notes to Consolidated Financial Statements and “Results of Operations—Generation” for additional detail related to the generating unit retirements.

(d)

Reflects the income statement impact for the years ended December 31, 2012 and 2011 primarily related to the increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units (net of taxes of $4 million and $11 million, respectively). Also reflects the reduction in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations in 2012 (net of taxes of $(3) million) and the reduction in PECO’s asset retirement obligation in 2011 (net of taxes of $(1) million). See Note 13 of the Combined Notes to Consolidated Financial Statements for additional information.

(e)

Reflects certain costs incurred in the years ended December 31, 2012 and 2011 (net of taxes of $161 million and $31 million, respectively) associated with the Constellation merger including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives. See Note 4 of the Combined Notes to the Consolidated Financial Statements for additional information.

(f)	Reflects certain costs incurred in the years ended December 31, 2012 and 2011 associated with various acquisitions (net of taxes of $2 million and $3 million, respectively). See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

(g)

Reflects a non-cash bargain purchase gain (negative goodwill) for the year ended December 31, 2011 in connection with the acquisition of Wolf Hollow, net of acquisition costs (net of taxes of $15 million). See Note 4 of the Combined Notes to the Consolidated Financial Statements for additional information.

(h)	Reflects a one-time benefit in 2011 to recover previously incurred costs as a result of the May 2011 ICC rate order (net of taxes of $5 million). See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.

(i)	Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger in 2012 and as a result of revised estimates of state apportionments in 2011. See Note 12 of the Combined Notes to the Consolidated Financial Statements for additional information.

(j)

Reflects the non-cash impact for the year ended December 31, 2012 (net of taxes of $491 million) of the amortization of intangible assets, net, related to commodity contracts recorded at fair value at the Constellation merger date. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.

(k)

Represents the non-cash amortization of certain debt for the year ended December 31, 2012 (net of taxes of $6 million) recorded at fair value at the Constellation merger date expected to be retired in 2013. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information.

(l)	Reflects costs incurred for the year ended December 31, 2012 associated with the Constellation merger (net of taxes of $101 million) as part of the Maryland order approving the merger transaction. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

(m)

Reflects costs incurred for the year ended December 31, 2012 (net of taxes of $23 million) as part of a settlement with the FERC to resolve a dispute related to Constellation’s pre-merger hedging and risk management transactions. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information.

(n)	Reflects estimated liabilities for the year ended December 31, 2012 (net of taxes of $5 million) pursuant to the Midwest Generation bankruptcy, primarily related to lease payments under a coal rail car lease and estimated payments for asbestos-related personal injury claims.

As discussed above, Exelon has incurred and will continue to incur costs associated with the Constellation merger, including meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former Constellation businesses into Exelon.

For the year ended December 31, 2012, expense has been recognized for costs incurred to achieve the merger as follows:


	Pre-tax Expense
	Twelve Months Ended December 31, 2012
Merger and Integration Costs:	Generation ^(a)		ComEd		PECO		BGE ^(a)		Exelon ^(a)
Transaction ^(b)	$	—	$	—	$	—	$	—	$	58
Maryland Commitments		35		—		—		139		328
Employee-Related ^(c)		138		3		11		2		164
Other ^(d)		167		2		6		7		196

Total	$	340	$	5	$	17	$	148	$	746

(a)	For Exelon, Generation and BGE, includes the operations of the acquired businesses from the date of the merger, March 12, 2012, through December 31, 2012.

(b)	External, third-party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing of the transaction.

(c)

Costs primarily for employee severance, pension and OPEB expense and retention bonuses. ComEd and BGE established regulatory assets of $21 million and $22 million, respectively; the majority of these costs are expected to be recovered over a five-year period. These costs are not included in the table above.

(d)	Costs to integrate Constellation processes and systems into Exelon and to terminate certain Constellation debt agreements. ComEd established a regulatory asset of $15 million for certain other merger and integration costs, which are not included in the table above.

As of December 31, 2012, Exelon projects incurring total additional merger-related expenses in 2013 and 2014 of approximately $135 million.

In addition, pursuant to conditions set forth by the MDPSC in its approval of the merger transaction, Generation expects to incur capital expenditures of $95 million to $120 million for the requirement to cause construction of a headquarters building in Baltimore for its competitive energy businesses (expected to be completed in 1 to 2 years) and up to $625 million for development of 285-300 MW of new electric generation facilities in Maryland (expected to be completed over the next ten years). The accounting treatment for the construction costs of the new headquarters building in Baltimore may vary depending on the structure of the transaction.

Exelon’s Strategy and Outlook for 2013 and Beyond

Exelon’s value proposition and competitive advantage come from its scope and scale across the energy value chain and its core strengths of operational excellence and financial discipline.

On March 12, 2012, the Exelon and Constellation merger was completed. The merger creates incremental strategic value by matching Exelon’s clean generation fleet with Constellation’s leading customer-facing platform, as well as creating economies of scale through expansion across the energy value chain. Exelon supports customer switching to alternative electric generation suppliers and the addition of Constellation’s competitive retail business provides another outlet for Exelon to grow its business in competitive markets.

Generation is managed as an integrated business and is located in multiple geographic regions, with multiple supply sources and provides various energy commodities through multiple distribution channels. Generation’s nuclear, fossil fuel, hydroelectric and renewables strategy is to pursue opportunities that provide generation to load matching and that diversify the generation fleet by expanding its regional and technological footprint. Generation’s customer-facing activities enhance its existing customer platform, expand the business across states and develop innovative products for its customers.

Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. Exelon seeks to leverage its scale and expertise across the utilities platform by standardization and sharing of best practices to achieve improved operational and financial results.

Exelon’s financial priorities are to maintain investment grade credit metrics at each of Exelon, Generation, ComEd, PECO and BGE, and to return value to Exelon’s shareholders with a sustainable dividend throughout the energy commodity market cycle and through earnings growth from attractive investment opportunities.

In pursuing its strategies, Exelon has exposure to various market and financial risks, including the risk of price fluctuations in the power markets. Power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular, the prices of natural gas and coal, which drive the market prices that Generation’s power plants can obtain for their output,

(2) the rate of expansion of subsidized low carbon generation in the markets in which Generation’s output is sold, (3) the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs, and (4) the impacts of increased competition in the retail channel.

Power Markets

Price of Fuels. The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Since the third quarter of 2011, forward natural gas prices for 2013 and 2014 have declined significantly; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).

Subsidized Generation. The rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.

Various states have implemented or proposed legislation, regulations or other policies to subsidize generation which thereby would artificially depress wholesale energy and capacity prices. For example, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland, that it projected will be in commercial operation by June 1, 2015. The CfD mandates that utilities (including BGE) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.

Similarly, in January 2011, New Jersey passed legislation that provides guaranteed cost recovery through a CfD for the development of up to 2,000 MWs of new base load or mid-merit generation, so long as it clears in PJM’s capacity market. Three generation developers were chosen for the New Jersey CfD, for which contracts were executed in 2011 by the state’s utilities under protest. Similarly, in Illinois, legislation has been debated for over four years that passed in the Senate and is currently being considered in the House which would require consumers to subsidize the development of an Integrated Gasification Combined Cycle plant by purchasing its electricity through 30 year power purchase agreements at prices significantly above market prices. A new version was recently introduced in the current General Assembly but its prospects are unclear at this time.

Exelon and others filed a complaint in federal district court challenging the constitutionality and other aspects of the New Jersey legislation. Similarly, Exelon and others are also challenging the selection of the three generation developers in New Jersey state court proceedings and the MDPSC actions in Maryland state court.

As required under their CfDs, two of the New Jersey generator developers and one in Maryland offered and cleared in PJM’s capacity market auction held in May 2012. Given the state-required customer subsidy provided under their respective CfDs, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in this auction and may continue to do so in future auctions to the detriment of Exelon’s market driven position. PJM’s capacity market rules include a Minimum Offer Pricing Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. However, Exelon does not believe that the existing MOPR worked effectively with respect to the abovementioned generator developers. Accordingly, Exelon worked with other market stakeholders, PJM and PJM’s independent market monitor to develop a new MOPR that would more effectively preclude such artificial price suppression,

and PJM, after extensive stakeholder consideration, filed its new MOPR seeking FERC approval in December, 2012. On February 5, 2013, the FERC issued a letter finding that PJM’s new MOPR filing is deficient and requested PJM provide additional information on several aspects of PJM’s MOPR proposal. PJM has 30 days to respond, and a FERC decision is expected within 60 days thereafter. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details of PJM’s MOPR.

A continuation of these state efforts, if successful and unabated by an effective MOPR, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish similar programs, which could substantially impair Exelon’s market driven position and could have a material effect on Exelon’s financial results of operations, financial position and cash flows.

Energy Demand. The continued sluggish economy in the United States has led to a decline in demand for electricity. ComEd is projecting load volumes to remain essentially flat in 2013 compared to 2012, while PECO and BGE are projecting a decline of 0.5% and 2.0%, respectively, in 2013 compared to 2012. The projected declines at PECO and BGE are a result of energy efficiency initiatives, the additional day in 2012 for the leap year and weak economic conditions in their service territories. The demand for electricity has also declined due to significantly milder than normal weather in 2012 and 2011. In addition, energy efficiency and demand response programs will result in decreased demand for energy. See Note 3 of the Combined Notes to Consolidated Financial Statements for further discussion of energy efficiency and demand response programs.

Retail Competition. Generation’s retail business competes for customers in a competitive environment which impacts the margins that Generation can earn and the volumes that it is able to serve. Recently, sustained low forward natural gas and power prices and low market volatility have caused retail competitors to aggressively pursue market share, and wholesale generators (including Generation) to use the retail channel to hedge generation output. These factors have negatively impacted overall gross margins and profitability in Generation’s business.

Strategic Policy Alignment

Exelon routinely reviews its hedging policy, dividend policies, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.

Exelon’s Board of Directors declared the first quarter 2013 dividend of $0.525 per share, and in response to low forward prices and weaker financial expectations, among other factors, Exelon’s Board of Directors approved a revised dividend policy going forward. The first quarter dividend is payable on March 8, 2013 to shareholders of record on February 19, 2013. The first quarter dividend is based on Exelon’s previous policy of $2.10 per share on an annualized basis, while the new dividend policy contemplates a regular $0.31 per share quarterly dividend beginning in the second quarter of 2013 (or $1.24 per share on an annualized basis). Consistent with past practice, all future quarterly dividends will require approval by Exelon’s Board of Directors.

If recent power price volatility and demand trends continue, they could adversely affect the Registrants’ ability to fund other discretionary uses of cash such as growth projects and dividends. In addition, economic conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation’s results of operations through increased depreciation rates, impairment charges and accelerated future decommissioning costs.

Hedging Strategy

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2013 and 2014. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of December 31, 2012, the percentage of expected generation hedged for the major reportable segments was 94%-97%, 62%-65% and 27%-30% for 2013, 2014, and 2015, 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 economic hedges and certain non-derivative contracts including sales to ComEd, PECO and BGE to serve their retail load. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.

Generation procures coal, oil and natural gas through long-term and short-term contracts 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, oil 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 60% of Generation’s uranium concentrate requirements from 2013 through 2017 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. ComEd, PECO and BGE mitigate exposure as a result of the regulatory mechanisms that allow them to recover procurement costs from retail customers.

New Growth Opportunities

with the power uprate initiative. Following these reviews, any projects that may be undertaken are expected to be completed by the end of 2021, and may result in between 1,125 and 1,200 MWs of additional capacity at an overnight cost of approximately $3.4 billion in 2013 dollars. Overnight costs do not include financing costs or cost escalation.

Generation Renewable Development. On September 30, 2011, Exelon announced the completion of its acquisition of all of the interests in Antelope Valley, a 230-MW solar photovoltaic (PV) project under development in northern Los Angeles County, California, from First Solar, Inc., which developed and will build, operate, and maintain the project. The first portion of the project began operations in December 2012, with additional blocks to come online and an expectation of full commercial operation by the end of the third quarter of 2013. The acquisition supports the Exelon commitment to renewable energy as part of Exelon 2020. The project has a 25-year PPA, approved by the CPUC, with Pacific Gas & Electric Company for the full output of the plant. Upon completion, the facility will add 230 MWs to Generation’s renewable generation fleet. Total costs for the facility are expected to be approximately $1.3 billion. Total costs incurred through December 31, 2012 were $679 million. Additionally, Generation constructed and placed into service six wind facilities in 2012, resulting in approximately 400 MWs of additional renewable generation. Total costs for the facilities were approximately $700 million. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission Development Project. Exelon and AEP Transmission Holding Company, LLC (AEP) are working collaboratively to develop an extra high-voltage transmission project from the western Ohio border through Indiana to the northern portion of Illinois. Referred to as the Reliability Interregional Transmission Extension (RITE) Line project, the project is expected to strengthen the high-voltage transmission system and improve overall system reliability. RITELine Illinois, LLC (RITELine Illinois) and RITELine Indiana, LLC (RITELine Indiana) have been formed as project companies to develop and own the project. RITELine Illinois will own the transmission assets located in Illinois and is owned 75% by ComEd and 25% by RITELine Transmission Development Company, LLC (RTD). RITELine Indiana will own the transmission assets located in Indiana and is owned by AEP (75%) and RTD (25%). Exelon Transmission Company, LLC and AEP each own 50% of RTD. The total cost of the RITE Line project is expected to be approximately $1.6 billion, with the Illinois portion of the line expected to cost approximately $1.2 billion. The ultimate cost of the line is dependent on a

number of factors, including RTO requirements, state siting requirements, routing of the line, and equipment and commodity costs. Exelon and AEP are pursuing the project for inclusion in PJM’s RTEP under yet-to-be finalized planning criteria. The current estimated in-service date is 2019.

On July 18, 2011, RITELine Illinois and RITELine Indiana filed at FERC for incentive rates and a formula rate for the RITE Line project. On October 14, 2011, FERC issued an order on the incentive and formula rate filing. The order grants a base rate of return on common equity of 9.9%, plus a 50 basis point adder for the project being in a RTO and a 100 basis point adder for the risks and challenges of the project, resulting in a total rate of return on common equity of 11.4%. The order grants a hypothetical capital structure of 45% debt and 55% equity until any part of the project enters commercial operations. The order also grants 100% recovery for construction work in progress, 100% recovery for abandonment, if the line is abandoned through no fault of the RITELine developers, and the ability to treat pre-construction costs as a regulatory asset. All incentives, including the abandonment incentive, are contingent on inclusion of the project in the PJM RTEP. The RITELine companies filed for rehearing on several rate of return on common equity issues and argued that the right to collect abandoned costs should not be subject to the project being included in the RTEP. The RITELine companies also made a compliance filing as called for in the October 14, 2011 Order. FERC accepted this filing on March 16, 2012.

Smart Meter and Smart Grid Initiatives.

ComEd’s Smart Meter and Smart Grid Investments. On December 5, 2012, the ICC approved ComEd’s revised AMI Deployment Plan which includes the planned installation of 4 million electric smart meters. ComEd plans to invest approximately $1.3 billion on smart meters and smart grid under EIMA, including $1.0 billion through the AMI Deployment Plan.

PECO’s Smart Meter and Smart Grid Investments. In 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan, under which PECO will install more than 1.6 million smart meters. PECO plans to spend up to a total of $595 million and $120 million on its smart meter and smart grid infrastructure respectively, before considering the $200 million SGIG.

BGE Smart Grid Initiative. In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million electric and gas smart meters at an expected total cost of approximately $480 million, before considering the $200 million SGIG for smart grid and other related initiatives.

See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information on the utility infrastructure projects.

Liquidity

Exelon annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade rating while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

Exelon, Generation, ComEd, PECO and BGE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.5 billion, $5.3 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively. Generation has a bilateral credit facility with aggregate maximum availability of $0.3 billion.

On January 23, 2013, Generation entered into a two year $75 million bilateral letter of credit facility with a bank. This facility will solely be utilized by Generation to issue letters of credit. See Liquidity and Capital Resources for additional information.

Exposure to Worldwide Financial Markets. Exelon has exposure to worldwide financial markets. The ongoing European debt crisis has contributed to the instability in global credit markets. Further disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2012, approximately 31%, or $2.5 billion, of the Registrants’ aggregate total commitments were with European banks. The credit facilities include $8.3 billion in aggregate total commitments of which $6.5 billion was available as of December 31, 2012. There were no borrowings under the Registrants’ credit facilities as of December 31, 2012. See Note 11 of the Combined Notes to the Consolidated Financial Statements for additional information on the credit facilities.

Tax Matters

Exelon has exposure related to various uncertain tax positions which Exelon manages through planning and implementation of tax planning strategies. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information.

Environmental Legislative and Regulatory Developments.

Exelon supports the promulgation of certain environmental regulations by the U.S. EPA, including air, water and waste controls for electric generating units. See discussion below for further details. The air and waste regulations will have a disproportionate adverse impact on fossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and will likely result in the retirement of older, marginal facilities. Due to their low emission generation portfolio, Generation and CENG will not be significantly directly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been introduced in the U.S. Congress that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the consideration of such legislation is unknown.

Air Quality. In recent years, the U.S. EPA has been implementing a series of increasingly stringent regulations under the Clean Air Act relating to NAAQS for conventional air pollutants (e.g., NO_x, SO₂ and particulate matter) as well as stricter technology requirements to control HAPs (e.g., acid gases, mercury and other heavy metals) from electric generation units. The U.S. EPA continues to review and update its NAAQS with a tightened particulate matter NAAQS issued in December 2012 and a review of the current 2008 ozone NAAQS that is expected to result in a final revised ozone NAAQS sometime in 2014. These updates will potentially result in more stringent emissions limits on fossil-fuel electric generating stations. There continues to be opposition among fossil-fuel generation owners to the potential stringency and timing of these air regulations.

In July 2011, the U.S. EPA published CSAPR and in June 2012, it issued final technical corrections. CSAPR required 28 upwind states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in downwind states. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA had exceeded its authority in certain material aspects with respect to CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. Until the U.S. EPA re-issues CSAPR, Exelon cannot determine the impacts of the rule, including any that would impact power prices.

On December 16, 2011, the U.S. EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that owners of smaller, older, uncontrolled coal units will retire the units rather than make these investments. Coal units with existing controls that do not meet the MATS rule may need to upgrade existing controls or add new controls to comply. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon has been granted permission by the Court to intervene in support of the rule. A decision by the Court is expected sometime in 2013. The outcome of the appeal, and its impact on power plant operators’ investment and retirement decisions, is uncertain.

The cumulative impact of these air regulations could be to require power plant operators to expend significant capital to install pollution control technologies, including wet flue gas desulfurization technology for SO₂ and acid gases, and selective catalytic reduction technology for NO_x. Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS by January 1, 2015. In addition, Keystone already has SCR and Flue-gas desulfurization (FGD) controls in place.

On January 15, 2013, EPA issued a final rule for New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) for reciprocating internal combustion engines (RICE NESHAP/NSPS). The final rule allows diesel backup generators to operate for up to 100 hours annually under certain emergency circumstances without meeting emissions limitations, but requires units that operate over 15 hours to burn low sulfur fuel and report key engine information. The final rule eliminates after May 2014 the 50 hour exemption for peak shaving and other non-emergency demand response that was included in the proposed rule, and therefore, is not expected to result in additional megawatts of demand response to be bid into the PJM capacity auction.

In the absence of Federal legislation, the U.S. EPA is also moving forward with the regulation of GHG emissions under the Clean Air Act, including permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources that became effective January 2, 2011. On April 13, 2012, the U.S. EPA published proposed regulations for NSPS for GHG emissions from new fossil-fueled power plants greater than 25 MW that would require the plants to limit CO₂ emissions. Under the PSD regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case-by-case basis. The U.S. EPA is also expected to establish in 2013 GHG emission regulations for existing stationary sources under Section 111(d) of the Clean Air Act, and it is not yet known what the nature and impact of the final regulations will be.

Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions.

Water Quality. Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. On March 28, 2011, the U.S. EPA issued a proposed rule, and is required under a Settlement Agreement to issue a final rule by July 27, 2013. The proposed rule does not require closed cycle cooling (e.g., cooling towers) as the

best technology available, and also provides some flexibility in the use of cost-benefit considerations and site-specific factors. The proposed rule affords the state permitting agency wide discretion to determine the best technology available, which, depending on the site characteristics, could include closed cycle cooling, advanced screen technology at the intake, or retention of the current technology.

It is unknown at this time whether the final regulations will require closed-cycle cooling. The economic viability of Generation’s facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost—benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation.

Hazardous and Solid Waste. Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion residuals (CCR) would be regulated for the first time under the RCRA. The U.S. EPA is considering several options, including classification of CCR either as a hazardous or non-hazardous waste, under RCRA. Under either option, the U.S. EPA’s intention is the ultimate elimination of surface impoundments as a waste treatment process. For plants affected by the proposed rules, this would result in significant capital expenditures and variable operating and maintenance expenditures to convert to dry handling and disposal systems and installation of new waste water treatment facilities. The Generation plants that would be affected by the proposed rules are Keystone and Conemaugh in Pennsylvania which have on-site landfills that meet the requirements of Pennsylvania solid waste regulations for non-hazardous waste disposal. However, until the final rule is adopted, the impact on these facilities is unknown. The U.S. EPA has not announced a target date for finalization of the CCR rules.

See Note 19 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

Other Regulatory and Legislative Actions

Japan Earthquake and Tsunami and the Industry’s Response. On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co.

Generation believes its nuclear generating facilities do not have the same operating risks as the Fukushima Daiichi plant because they meet the NRC’s requirement that specifies all plants must be able to withstand the most severe natural phenomena historically reported for each plant’s surrounding area, with a significant margin for uncertainty. In addition, Generation’s plants are not located in significant earthquake zones or in regions where tsunamis are a threat. Generation believes its nuclear generating facilities are able to shut down safely and keep the fuel cooled through multiple redundant systems specifically designed to maintain electric power when electricity is lost from the grid. Further, Generation’s nuclear generating facilities also undergo frequent scenario drills to ensure the proper function of the redundant safety protocols.

Since the events in Japan took place, Generation has continued to work with regulators and nuclear industry organizations to understand the events in Japan and apply lessons learned. Early on, the nuclear industry took a number of specific steps to respond, including actions requested by the Institute of Nuclear Power Operations (INPO) to perform tests that verified Generation’s emergency equipment is available and functional, conduct walk-downs on its procedures related to critical safety equipment, confirm event response procedures and readiness to protect the spent fuel pool, and verify current qualifications of operators and support staff needed to implement the procedures. Generation has been addressing additional actions requested by INPO for improving and maintaining core and spent fuel pool cooling during an extended loss of power for at least 24 hours.

In April 2011, the NRC named six senior managers and staff to its task force for examining the agency’s regulatory requirements, programs, processes, and implementation in light of information from the Fukushima Daiichi site in Japan, following the March 11 earthquake and tsunami (Task Force). On July 12, 2011, the NRC Task Force issued a report of its review of the accident, including recommendations for future regulatory action by the NRC to be taken in the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The Task Force’s report did not recommend any changes to the existing nuclear licensing process in the United States or changes in the storage of spent nuclear fuel within the plant’s spent nuclear fuel pools. During the fourth quarter of 2011, the NRC staff issued its recommendations for prioritizing and implementing the Task Force recommendations and an implementation schedule which was approved by the NRC subject to a number of conditions. The NRC staff confirmed the Task Force’s conclusions that none of the findings arising from the Task Force review presented an imminent risk to public health and safety.

In March 2012, the NRC authorized its staff to issue three immediately effective orders to commercial reactor licensees operating in the United States for compliance no later than December 31, 2016. In summary, the orders require licensees: (1) to provide sufficient onsite portable equipment and resources to maintain or restore cooling capabilities for the containment, core, and spent fuel pool until offsite equipment is available and have offsite equipment and resources available to sustain cooling functions indefinitely; (2) to improve the venting systems with boiling water reactor Mark I or Mark II containments (or for the Mark II plants, install new systems) that help prevent or mitigate core damage in the event of a serious accident by making the systems accessible and operable in the event of a prolonged station blackout and inadequate cooling; and (3) to install instrumentation to provide a reliable indication of water level in the spent fuel pool.

Additionally, the NRC has issued a detailed information request to every operating commercial nuclear power plant in the United States. The information requested requires: (1) use of the current NRC guidance to reevaluate current seismic and flood risk hazards against the design basis and provide a plan of actions to address vulnerabilities, including risks exceeding the design basis; (2) performance of walk downs to ensure the ability to respond to seismic and external flooding events and provide a corrective action plan to the NRC to address deficiencies; and (3) assessment of the means to provide power for communications equipment during a severe natural event and identify staffing required to implement the emergency plan for an event affecting all units with an extended loss of alternating current power and impeded access to the site. In November 2012, the NRC staff recommended to the NRC the installation of engineered containment filtered venting systems for boiling-water reactors with Mark I and Mark II containment structures. The NRC is currently reviewing the staff recommendations.

Generation has assessed the impacts of the orders and information requests and will continue monitoring the additional recommendations under review by the staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance is expected to be approximately $350 million and $50 million of capital and operating expense, respectively, from 2013 through 2017, as previously anticipated in Generation’s planning projections. In addition, Generation estimates incremental costs of $15 to $20 million per unit at eleven Mark I and II units for the installation of filtered vents, if ultimately required by the NRC. Generation’s current assessments are specific to the Tier 1 recommendations as the NRC has not taken specific action with respect to the Tier 2 and Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industry assessments and actions and stakeholder input. See Item 1A. Risk Factors, for further discussion of the risk factors.

Financial Reform Legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for over-the-counter swaps (Swaps), including mandatory clearing, exchange trading, margin requirements, and other transparency requirements. The Dodd-Frank Act, however, also preserves the ability of end users in the energy industry to hedge their risks. In April 2012, the CFTC issued its rule defining swap dealers and major swap participants. Exelon has determined that it will conduct its commercial business in a manner that does not require registration as a swap dealer or major swap participant. Notwithstanding, there are additional rulemakings that have not yet been issued, including the capital and margin rules, which will further define the scope of the regulations and provide clarity as to the impact on the Registrants’ business, as well as to potential new opportunities. Depending on these final rules, the Registrants could be subject to significant new obligations.

The proposed regulations addressing collateral and capital requirements and exchange margin cash postings, when final, could require Generation to increase collateral requirements or cash postings in lieu of letters of credit currently issued to collateralize Swaps. Exelon had previously estimated that it could be required to make up to $1 billion of additional collateral postings under its bilateral credit lines. Given the swap dealer and the major swap participant definitions will not apply to Generation, the actual amount of collateral postings that will be required may be lower than Exelon’s previous expectations due to the following factors: (a) the majority of Generation’s physical wholesale portfolio does not meet the final CFTC Swap definition; (b) there will be minimal incremental costs associated with Generation’s positions that are currently cleared and subject to exchange margin; and (c) Generation will not be a swap dealer or major swap participant and proposed capital requirements applicable to these entities will not apply to Generation.

The actual level of collateral required will depend on many factors, including but not limited to market conditions, the outcome of final margin rules for Swaps, the extent of its trading activity in Swaps, and Generation’s credit ratings. Nonetheless, Generation has adequate credit facilities and flexibility in its hedging program to meet its anticipated collateral requirements estimated based on conservative assumptions.

In addition, the new regulations will impose new and ongoing compliance and infrastructure costs on Generation, which may amount to several million dollars per year.

Generation continues to monitor the rulemaking procedures and cannot predict the ultimate outcome that the financial reform legislation will have on its results of operations, cash flows or financial position.

Energy Infrastructure Modernization Act. Since 2011, ComEd’s distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois’ electric utility infrastructure. In addition, as long as ComEd is subject to EIMA, ComEd will fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates.

ComEd files an annual reconciliation of the revenue requirement in effect in a given year to reflect the actual costs that the ICC determines are prudently and reasonably incurred for such year. Under the terms of EIMA, ComEd’s target rate of return on common equity is subject to reduction if ComEd does not deliver the reliability and customer service benefits, as defined, it has committed to over the ten-year life of the investment program. See 3 of the Combined Notes to Consolidated Financial Statements for additional information.

FERC Ameren Order. In July 2012, FERC issued an order to Ameren Corporation indicating that Ameren had improperly included acquisition premiums/ goodwill in its transmission formula rate, particularly in its capital structure and in the application of AFUDC. FERC also directed Ameren to make refunds for the implied increase in rates in prior years. Ameren has filed for rehearing regarding the July 2012 FERC order. ComEd believes that the FERC order authorizing its transmission formula rate is distinguishable from the circumstances that led to the July 2012 FERC order in the Ameren case. However, if ComEd were required to exclude acquisition premiums/ goodwill from its transmission formula rate, the impact could be material to ComEd’s results of operations and cash flows.

Reliability and Quality of Service Standards. During its 2011 legislative session, the Maryland General Assembly passed legislation:

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directing the MDPSC to enact service quality and reliability regulations by July 1, 2012 relating to the delivery of electricity to retail electric customers,

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increasing existing penalties for failure to meet these and other MDPSC regulations, and

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directing the MDPSC to undertake certain studies addressing utility liability for certain customer damages, electric utility service restoration plans, and modifications to existing revenue decoupling mechanisms for extended service interruptions.

In May 2011, the Governor of Maryland signed this legislation into law. The related new service quality and reliability regulations became effective on May 28, 2012. These regulations could have a material impact on BGE’s financial results of operations, cash flows and financial position. BGE did seek recovery of these costs in the current base rate case filed on July 27, 2012.

2012 Maryland Electric and Gas Distribution Rate Case. On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October, 22, 2012, BGE updated its application to request an increase of $131 million and $45 million to its electric and gas base rates, respectively. The new electric and gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

FERC Order No. 1000 Compliance (ComEd, PECO and BGE). In FERC Order No. 1000, the FERC required public utility transmission providers to enhance their transmission planning procedures and their cost allocation methods applicable to certain new regional and interregional transmission projects. As part of the changes to the transmission planning procedures, the FERC removed from all FERC-approved tariffs and agreements a federal right of first refusal to build certain new transmission facilities. In compliance with the regional transmission planning requirements of Order No. 1000, PJM as the transmission provider submitted a compliance filing to FERC on October 25, 2012. On the same day, certain of the PJM transmission owners including ComEd, PECO and BGE (collectively, the PJM Transmission Owners) submitted a filing asserting that their contractual rights embodied in the PJM governing documents continue to justify their right of first refusal to construct new reliability (and related) transmission projects and that the FERC should not be allowed to override such rights absent a showing that it is in the public interest to do so under the FERC’s “Mobile-Sierra” standard of review. This is a heightened standard of review which the PJM Transmission Owners argued could not be satisfied based on the facts applicable to them. Although this heightened standard of review should make it more difficult for the FERC or any third party to override the PJM Transmission Owners’ right to build such transmission projects, there is risk that the FERC will find that the heightened standard of review does not apply to protect the PJM Transmission Owners rights and/or find that whatever standard is applied has been satisfied. Such a FERC finding could enable third parties to seek to build certain regional transmission projects that had previously been reserved for the PJM Transmission Owners, potentially reducing ComEd’s, PECO’s and BGE’s financial return on new investments in energy transmission facilities.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management discusses these policies, estimates and assumptions with its accounting and disclosure governance committee on a regular basis and provides periodic updates on management decisions to the audit committee of the Exelon board of directors. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions 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. Generation’s ARO associated with decommissioning its nuclear units was $4.7 billion at December 31, 2012.

The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios. The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the methodologies and significant estimates and assumptions described as follows:

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

Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning costs, approaches and timing on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. Probabilities are assigned to alternative decommissioning approaches which assess the likelihood of performing DECON (a method of decommissioning shortly after the cessation of operation 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), 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)

decommissioning. 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 assumed would begin in 2025 and 2020 in 2012 and 2011, respectively. The change in the SNF acceptance date was based on management’s estimates of the amount of time required for the DOE to select a site location and develop the necessary infrastructure. For more information regarding the estimated date that DOE will begin accepting SNF, see Note 19 of the Combined Notes to Consolidated Financial Statements.

License Renewals. Generation assumes a successful 20-year renewal for each of its nuclear generating station licenses, except for Oyster Creek, in determining its nuclear decommissioning ARO. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information on Oyster Creek. Generation has successfully secured 20-year operating license renewal extensions for ten of its nuclear units (including the two Salem units co-owned by Generation, but operated by PSEG), and none of Generation’s applications for an operating license extension have been denied. Generation is in various stages of the process of pursuing similar extensions on its remaining nine operating nuclear units. Generation’s assumption regarding license extension for ARO determination purposes is based in part on the good current physical condition and high performance of these nuclear units; the favorable status of the ongoing license renewal proceedings with the NRC, and the successful renewals for ten units to date. Generation estimates that the failure to obtain license renewals at any of these nuclear units (assuming all other assumptions remain constant) would increase its ARO on average approximately $250 million per unit as of December 31, 2012. The size of the increase to the ARO for a particular nuclear unit is dependent upon the current stage in its original license term and its specific decommissioning cost estimates. If Generation does not receive license renewal on a particular unit, the increase to the ARO may be mitigated by Generation’s ability to delay ultimate decommissioning activities under a SAFSTOR method of decommissioning.

Discount Rates. The probability-weighted estimated future cash flows using these various scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. The accounting guidance required Generation to establish an ARO at fair value at the time of the initial adoption of the current accounting standard. Subsequent to the initial adoption, the ARO is adjusted for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions, as described above.

Under the current accounting framework, the ARO is not required or permitted to be re-measured, from period to period, for changes in the CARFR that occur in isolation. This differs from the accounting requirements for other long-dated obligations, such as pension and other post-employment benefits that are required to be re-measured as and when corresponding discount rates change. If Generation’s future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFRs, the obligation would increase from approximately $4.7 billion to approximately $7.5 billion. The ultimate decommissioning obligation will be funded by the NDTs. The NDTs are recorded on Exelon’s and Generation’s Consolidated Balance Sheets at December 31, 2012 at fair value of approximately $7.2 billion and have an estimated targeted annual pre-tax return of 5.3% to 6.2%.

To illustrate the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO: i) had Generation used the 2011 CARFRs rather than the 2012 CARFRs in performing its third quarter 2012 ARO update, Generation would have reduced the ARO by approximately $50 million as compared to the actual increase to the ARO of $669 million; and ii) if the CARFR used in performing the third quarter 2012 ARO update (which also reflected increases in the amounts and changes to the timing of projected cash flows) was increased or decreased by 100 basis points, the ARO would have increased by $110 million and $1.6 billion, respectively, as compared to the actual increase of $669 million.

ARO Sensitivities. Changes in the assumptions underlying the foregoing items could materially affect the decommissioning obligation. The impact to the ARO of a change in any one of these assumptions is highly dependent on how the other assumptions will change as well. As an example, the significant changes in the value of the ARO during 2012 were driven primarily by Generation modifying the assumed timing of the DOE acceptance of SNF for disposal from 2020 to 2025 during the third quarter 2012 annual ARO update. The modification of the assumed DOE acceptance date impacted the calculation of the ARO in isolation as follows; i) the change in the timing of DOE acceptance of SNF increased the total number of years in which decommissioning activities are estimated to occur, by five years on average, thereby increasing the total expected nominal cash flows required to decommission the units; ii) the nominal cash flows were subjected to additional escalation as a result of the extension of the decommissioning period increasing the total estimated costs required to decommission the units; and iii) the escalated cash flows were then discounted at the then current CARFRs which have dramatically decreased in 2012 given the current low interest rate environment. The change in the timing and amount of cash flows as a result of the change in the assumed DOE acceptance date in combination with the significant decrease in the 2012 CARFRs were the primary drivers of the third quarter 2012 ARO update total increase of $669 million.

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, 2012
Cost escalation studies
Uniform increase in escalation rates of 25 basis points	$	820
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	$	250
Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of the SAFSTOR scenario by 10 percentage points	$	360
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	$	490
Extend the estimated date for DOE acceptance of SNF to 2030	$	700
Extend the estimated date for DOE acceptance of SNF to 2030 coupled with an increase in discount rates of 100 basis points	$	30
Extend the estimated date for DOE acceptance of SNF to 2030 coupled with a decrease in discount rates of 100 basis points	$	1,570

For more information regarding accounting for nuclear decommissioning obligations, see Notes 1 and 13 of the Combined Notes to Consolidated Financial Statements.

Goodwill (Exelon and ComEd)

As of December 31, 2012, Exelon’s and ComEd’s carrying amount of goodwill was approximately $2.6 billion, relating to the acquisition of ComEd in 2000 as part of the PECO/Unicom Merger. Under the provisions of the authoritative guidance for goodwill, ComEd is required to perform an assessment for possible impairment of its 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. Under the authoritative guidance, a reporting unit is an operating segment or operating component and is the level at which goodwill is tested for impairment. In September 2011, the FASB issued authoritative guidance amending existing guidance on the annual assessment of goodwill for impairment. Under the revised

guidance, which became effective January 1, 2012, entities assessing goodwill for impairment have the option of performing a qualitative assessment rather than the quantitative assessment previously required. In performing a qualitative assessment, entities should assess, among other things, macroeconomic conditions, industry and market considerations, overall financial performance, cost factors, and entity-specific events. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If an entity bypasses the qualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount, a two-step, fair value based test is performed. 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. Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s business and the fair value of debt. In applying the second step (if needed), management must estimate the fair value of specific assets and liabilities of the reporting unit.

ComEd performed an interim goodwill impairment assessment as of May 31, 2012, as a result of the ICC’s final Order (Order) in ComEd’s 2011 formula rate proceeding under the EIMA that reduced ComEd’s annual revenue requirement being recovered in current rates by $168 million. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. Based on the results of the interim goodwill test performed as of May 31, 2012, the estimated fair value of ComEd would have needed to decrease by more than 10 percent for ComEd to fail the first step of the impairment test.

ComEd performed a qualitative assessment as of November 1, 2012, for its 2012 annual goodwill impairment assessment and while certain factors indicated a reduction in fair value since May 31, 2012, ComEd determined its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform a quantitative assessment.

While neither the interim nor the annual assessments indicated an impairment of ComEd’s goodwill, a change in management’s assumption regarding the outcome of the IRS challenge of Exelon’s and ComEd’s like-kind exchange income tax position, adverse regulatory actions such as early termination of EIMA or changes in significant assumptions described above could potentially result in a future impairment of ComEd’s goodwill, which could be material. ComEd will assess whether its goodwill has been impaired in the first quarter of 2013 in connection with the reassessment of the like-kind exchange position and the associated charge to ComEd’s earnings. See Notes 1, 8 and 12 of the Combined Notes to Consolidated Financial Statements for additional information.

Purchase Accounting (Exelon and Generation)

In accordance with the authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the balance sheet if it exceeds the estimated fair value and as a bargain purchase gain on the income statement if it is below the estimated fair value. Determining the fair value of assets acquired and

liabilities assumed requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

Unamortized Energy Assets and Liabilities (Exelon and Generation)

Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired. The initial amount recorded represents the fair value of the contract at the time of acquisition, and the balance is amortized over the life of the contract in relation to the present value of the underlying cash flows. Amortization expense and income are recorded through purchased power and fuel expense or operating revenues. Refer to Note 4—Mergers and Acquisitions and Note 8—Intangible Assets for further discussion.

Impairment of Long-lived Assets (Exelon, Generation, ComEd, PECO and BGE)

Exelon, Generation, ComEd, PECO and BGE evaluate their long-lived assets and asset groups, excluding goodwill, for impairment 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 prices 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, among others. Continued declines in natural gas prices have impacted fundamental views of market power prices, which could indicate a potential impairment to the Registrants’ long-lived assets and asset groups, which are primarily made up of generating assets. The Registrants regularly monitor their long-lived assets for these circumstances to determine whether or not an impairment evaluation is required.

The review of long-lived assets and asset groups 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 recoverability of an asset or asset group 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 or asset groups 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 and associated intangible contract assets recorded on the balance sheet. The cash flows from the generation units are evaluated at a regional portfolio level with cash flows generated from Generation’s customer supply and risk management activities, including cash flows from contracts that are accounted for as intangible contract assets and liabilities recorded on the balance sheet. For ComEd, PECO and BGE, 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 provided. For ComEd, the lowest level of independent cash flows is transmission and distribution and for PECO and BGE, 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. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market discount rates. Events and circumstances frequently do not occur as expected and there will usually be differences between prospective financial information and actual results, and those differences may be material. Accordingly, to the extent that any of the information used in the fair value analysis requires adjustment, the resulting fair market value would be different. As such, the determination of fair value is driven by both internal assumptions as well as information from various public, financial and industry sources. An impairment determination would require the affected Registrant to reduce either the long-lived asset or asset group, including any intangible contract assets and liabilities, and current period earnings by the amount of the impairment.

Generation evaluates unproved gas producing properties at least annually to determine if they are impaired. Impairment for unproved gas property occurs if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance.

Exelon holds certain investments in coal-fired plants in Georgia and Texas subject to long-term leases. Exelon determines the investment in these plants by incorporating an estimate of the residual values of the leased assets which equates to the fixed purchase option prices established at the inception of the leases. On an annual basis, Exelon reviews the estimated residual values of these plants to determine if the current estimate of their residual value is lower than the one originally established. In determining the current estimate of the residual value the expectation of future market conditions, including commodity prices, is considered. If the current estimate of the residual value is lower than the residual value established at the inception 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.

Generation also evaluates its equity method investments, including CENG, to determine whether or not they are impaired based on whether the investment has experienced an other than temporary decline in value. Additionally, if Generation’s equity method investments recognize an impairment, Generation would record its proportionate share of that impairment loss through its equity earnings (losses) of unconsolidated affiliates. Generation would also evaluate the investment for an other than temporary decline in value at that time.

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, PECO and BGE)

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. See Note 1 of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant and equipment of the Registrants.

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 except for Oyster Creek. 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 evaluates every three to five years the estimated service lives of its fossil fuel generating and renewable facilities based on feasibility assessments as well as economic and capital requirements. The estimated service lives of hydroelectric facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the Conowingo and Muddy Run 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. Generation completed a depreciation rate study during the first quarter of 2010, which resulted in the implementation of new depreciation rates effective January 1, 2010. Constellation completed a depreciation rate study during the fourth quarter of 2010, which resulted in the implementation of new depreciation rates effective during the fourth quarter of 2010.

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 April 2010, 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 January 1, 2010 for electric transmission assets and January 1, 2011 for electric distribution and gas assets.

The MDPSC does not mandate the frequency or timing of BGE’s depreciation studies. In December 2006, BGE filed revised depreciation rates with the MDPSC for both its electric distribution and gas assets. Revisions to depreciation rates from this filing were finalized July 1, 2010.

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

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for substantially all Generation, ComEd, PECO, BGE and BSC employees. See Note 14 of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefit plans.

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit pension and other postretirement benefit plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon’s expected level of contributions to the plans, 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, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. The impact of assumption

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changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. Pension and other postretirement benefit costs attributed to the operating companies are labor costs and are ultimately allocated to projects within the operating companies, some of which are capitalized.

Pension and other postretirement benefit plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity and hedge funds. See Note 14 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 under the fair value hierarchy in accordance with authoritative guidance.

Expected Rate of Return on Plan Assets. The long-term expected rate of return on plan assets assumption used in calculating pension costs was 7.50%, 8.00% and 8.50% for 2012, 2011 and 2010, respectively. The weighted average expected return on assets assumption used in calculating other postretirement benefit costs was 6.68%, 7.08% and 7.83% in 2012, 2011 and 2010, respectively. The pension trust activity is non-taxable, while other postretirement benefit trust activity is partially taxable. The current year EROA is based on asset allocations from the prior year end. In 2010, Exelon began implementation of a liability driven investment strategy in order to reduce the volatility of its pension assets relative to its pension liabilities. As a result of this modification, over time, Exelon determined that it will decrease equity investments and increase investments in fixed income securities and alternative investments in order to achieve a balanced portfolio of liability hedging and return-generating assets. The change in the overall investment strategy would tend to lower the expected rate of return on plan assets in future years as compared to the previous strategy. See Note 14 of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s asset allocations. Exelon used an EROA of 7.50% and 6.45% to estimate its 2013 pension 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 the majority of 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 and certain pension plan assets, Exelon uses fair value to calculate the MRV.

Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and other postretirement benefit plans. The actual asset returns across the Registrants’ pension and other postretirement benefit plans for the year ended December 31, 2012 were 12.8% and 12.5%, respectively, compared to an expected long-term return assumption of 7.50% and 6.68%, respectively.

Discount Rate. The discount rates used to determine the pension and other postretirement benefit obligations were 3.92% and 4.00%, respectively, at December 31, 2012. The discount rates at December 31, 2012 represent weighted-average rates for both legacy Exelon and Constellation pension and other postretirement benefit plans. At December 31, 2012 and 2011, the discount rates were 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

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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 determine the discount rates.

The discount rate assumptions used to determine the obligation at year end are used to determine the cost for the following year. Exelon will use discount rates of 3.92% and 4.00% to estimate its 2013 pension and other postretirement benefit costs, respectively.

Health Care Reform Legislation. In March 2010, the Health Care Reform Acts were signed into law, which contain a number of provisions that impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer’s postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to those offered by Medicare. Although this change did not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. Additionally, as a result of this deductibility change for employers and other Health Care Reform provisions that impact the federal prescription drug subsidy options provided to employers, Exelon changed the manner in which it will receive prescription drug subsidies beginning in 2013.

The Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Although the excise tax does not go into effect until 2018, accounting guidance requires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Effective in 2002, Constellation amended its other postretirement benefit plans for all subsidiaries other than Nine Mile Point by capping retiree medical coverage for future retirees who were under the age of 55 on January 1, 2002 at 2002 levels. Therefore, the excise tax is not expected to have a material impact on the legacy Constellation other postretirement benefit plans. However, certain key assumptions are required to estimate the impact of the excise tax on the other postretirement obligation for legacy Exelon plans, including projected inflation rates (based on the CPI) and whether pre- and post-65 retiree populations can be aggregated in determining the premium values of health care benefits. Exelon reflected its best estimate of the expected impact in its annual actuarial valuation.

Health Care Cost Trend Rate. Assumed health care cost trend rates have a significant effect on the costs reported for Exelon’s other postretirement benefit plans. Accounting guidance requires that annual health care cost estimates be developed using past and present health care cost trends (both for Exelon and across the broader economy), as well as expectations of health care cost escalation, changes in health care utilization and delivery patterns, technological advances and changes in the health status of plan participants. Therefore, the trend rate assumption is subject to significant uncertainty, particularly when considering potential impacts of the 2010 Health Care Reform Acts. Exelon assumed an initial health care cost trend rate of 6.50% at December 31, 2012, decreasing to an ultimate health care cost trend rate of 5.00% in 2017.

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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 2012 cost:
Discount rate ^(a)	0.5%	$	(61	)	$	(26	)	$	(87	)
	(0.5%)		60			29			89
EROA	0.5%		(66	)		(9	)		(75	)
	(0.5%)		66			9			75
Health care cost trend rate	1.00%		N/A			81			81
	(1.00%)		N/A			(56	)		(56	)
Change in benefit obligation at December 31, 2012:
Discount rate ^(a)	0.5%		(987	)		(340	)		(1,327	)
	(0.5%)		1,094			367			1,461
Health care cost trend rate	1.00%		N/A			845			845
	(1.00%)		N/A			(569	)		(569	)

(a)

In general, the discount rate will have a larger impact on the pension and other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon implemented a liability-driven investment strategy for a portion of its pension asset portfolio in 2010. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.

Average Remaining Service Period. For pension benefits, Exelon amortizes its unrecognized prior service costs and certain actuarial gains and losses, as applicable, based on participants’ average remaining service periods. The average remaining service period of defined benefit pension plan participants was 11.9 years, 12.1 years and 12.4 years for the years ended December 31, 2012, 2011 and 2010, respectively.

For other postretirement benefits, Exelon amortizes its unrecognized prior service costs over participants’ average remaining service period to benefit 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 postretirement benefit plan participants related to benefit eligibility age was 8.9 years, 6.6 years and 6.8 years for the years ended December 31, 2012, 2011 and 2010, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 10.1 years, 8.7 years and 9.0 years for the years ended December 31, 2012, 2011 and 2010, respectively.

Regulatory Accounting (Exelon, ComEd, PECO and BGE)

Exelon, ComEd, PECO and BGE 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, PECO and BGE to reflect the effects of cost-based rate regulation in their financial statements. This guidance is applicable to entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates are set at levels that will recover the entities costs from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to

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customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. As of December 31, 2012, Exelon, ComEd, PECO and BGE have concluded that the operations of ComEd, PECO and BGE meet the criteria to apply the authoritative guidance. 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, PECO and BGE would be required to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the Consolidated Statements of Operations and could be material. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon, ComEd, PECO and BGE.

For each regulatory jurisdiction in which they conduct business, Exelon, ComEd, PECO and BGE assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in ComEd’s, PECO’s and BGE’s jurisdictions, and factors such as changes in applicable regulatory and political environments. Furthermore, Exelon, ComEd, PECO and BGE 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, if any, to which costs will be recoverable through rates. Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ComEd’s distribution formula rate tariff, pursuant to EIMA, and FERC-approved transmission formula rate tariffs for ComEd and BGE. Additionally, estimates are made in accordance with the authoritative guidance for contingencies as to the amount of revenues billed under certain regulatory orders that may ultimately be refunded to customers upon finalization of applicable regulatory or judicial processes. These assessments are based, to the extent possible, on past relevant experience with regulatory bodies in ComEd’s, PECO’s and BGE’s jurisdictions, known circumstances specific to a particular matter and hearings held with the applicable regulatory body. If the assessments and estimates made by Exelon, ComEd, PECO and BGE are ultimately different than actual regulatory outcomes, the impact on their results of operations, financial position, and cash flows could be material.

The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.

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

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 and floating-to-fixed energy swaps with several unaffiliated suppliers that extend into 2032. PECO has entered into derivative natural gas contracts to hedge its long-term price risk in the natural gas market. PECO has also entered into derivative contracts to procure electric supply through a competitive RFP process as outlined in its PAPUC-approved DSP Program. BGE has also entered into derivative contracts to procure electric supply through a competitive auction process as outlined in its MDPSC-approved SOS Program. ComEd, PECO and BGE 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 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

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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, exchange traded contracts to purchase and sell capacity in certain ISO’s, certain emission products and RECs do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement and neither the uranium, certain capacity, emission nor the REC markets are sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. If these markets do become sufficiently liquid in the future and Generation would be required to account for these 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 mark-to-market gains or losses, which may have a significant 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, except for certain derivatives that qualify for, and are elected under, the 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 commodity transactions, effective with the date of merger with Constellation, Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation’s designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all economic hedges for commodities are recorded at fair value through earnings for the combined company. For economic hedges that are not designated for hedge accounting and for energy-related derivatives entered into for proprietary trading purposes, changes in the fair value of the derivatives are recognized in earnings each period except for ComEd, PECO and BGE, in which changes in the fair value each period are recorded as 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 is not financially settled on a net basis. 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

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markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying 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 ComEd’s energy procurement process, PECO’s full requirement contracts and block contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreements and all of BGE’s full requirement contracts and 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, PECO and BGE. 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 financial rather than physical contract settlements.

Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP and the forecasted future transaction is probable. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.

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 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 traded 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, and 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, the 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, the 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 to date have generally not been material to the financial statements.

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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 the 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 and floating to fixed swaps for project financing. In addition, Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the economic hedge and proprietary trading activity is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or change in market interest rates. The fair value of the agreements is calculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate curves. 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 9 and 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

Taxation (Exelon, Generation, ComEd, PECO and BGE)

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. In accordance with applicable authoritative guidance, the Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position 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. 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 their intent and ability to implement tax planning strategies, 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, 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, 2012 and 2011 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of tax matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding taxes.

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

In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amounts recorded may differ from the actual expense incurred when the uncertainty is resolved. The estimates that the Registrants make in accounting for loss contingencies and the actual results 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. Periodic studies are conducted at ComEd, PECO and BGE to determine future remediation requirements and estimates are adjusted accordingly. In addition, periodic reviews are performed at Generation to assess the adequacy of its environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant effect on the Registrants’ results of operations, financial position and cash flows. See Note 19 of the Combined Notes to Consolidated Financial Statements for further information.

Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, 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. 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 state and national legislative measures 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.

Revenue Recognition (Exelon, Generation, ComEd, PECO and BGE)

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, PECO’s and BGE’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. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, 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. In addition, volumes may fluctuate monthly as a result of customers electing to use an alternate supplier, which could be significant to the calculation of unbilled revenue since unbilled commodity receivables are not recorded for these customers. 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 measurement of unbilled revenue; however, total operating revenues would remain materially unchanged.

ComEd’s distribution formula rate tariff, pursuant to EIMA, provides for annual reconciliations to the distribution revenue requirement. As of the balance sheet dates, ComEd has recorded its best estimates of the distribution revenue impact resulting from changes in rates that ComEd believes are probable of approval by the ICC in accordance with the formula rate mechanism. Estimates are based

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upon actual costs incurred and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be impacted by, among other things, variances in costs incurred and investments made and actions by regulators or courts.

ComEd’s and BGE’s transmission formula rate tariffs, pursuant to FERC, provide for annual reconciliations to the transmission revenue requirements. As of the balance sheet dates, ComEd and BGE have recorded the best estimate of their respective transmission revenue impact resulting from changes in rates that ComEd and BGE believe are probable of approval by FERC in accordance with the formula rate mechanism. Estimates are based upon actual costs incurred and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be impacted by, among other things, variances in costs incurred and investments made and actions by regulators or courts.

Estimates are based upon actual costs incurred and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliations can be impacted by, among other things, variances in costs incurred and investments made and actions by regulators or courts.

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.

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

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on historical specific customer payment experience and other currently available information. ComEd and PECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by risk segment. Risk segments represent a group of customers with similar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. BGE estimates the allowance for uncollectible accounts on customer receivables by assigning reserve factors for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. ComEd, PECO and BGE 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, PECO and BGE customer accounts are written off consistent with approved regulatory requirements. ComEd’s, PECO’s and BGE’s provisions for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 5 of the Combined Notes to Consolidated Financial Statements for additional information regarding accounts receivable.

Results of Operations by Business Segment

The comparisons of operating results and other statistical information for the years ended December 31, 2012, 2011 and 2010 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

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Net Income (Loss) on Common Stock by Business Segment


	2012 ^(a)			2011		Favorable (unfavorable) 2012 vs. 2011 variance			2010		Favorable (unfavorable) 2011 vs. 2010 variance
Exelon	$	1,160		$	2,495	$	(1,335	)	$	2,563	$	(68	)
Generation		558			1,771		(1,213	)		1,972		(201	)
ComEd		379			416		(37	)		337		79
PECO		381			389		(8	)		324		65
BGE		(9	)		123		(132	)		134		(11	)

(a)	For BGE, reflects BGE’s operations for the year ended December 31, 2012. For Exelon and Generation, includes the operations of the Constellation and BGE from the date of the merger, March 12, 2012, through December 31, 2012.

Results of Operations—Generation


	2012 ^(b)			2011			Favorable (unfavorable) 2012 vs. 2011 variance			2010			Favorable (unfavorable) 2011 vs. 2010 variance
Operating revenues	$	14,437		$	10,447		$	3,990		$	10,025		$	422
Purchased power and fuel expense		7,061			3,589			(3,472	)		3,463			(126	)

Revenue net of purchased power and fuel expense ^(a)		7,376			6,858			518			6,562			296
Other operating expenses
Operating and maintenance		5,028			3,148			(1,880	)		2,812			(336	)
Depreciation and amortization		768			570			(198	)		474			(96	)
Taxes other than income		369			264			(105	)		230			(34	)

Total other operating expenses		6,165			3,982			(2,183	)		3,516			(466	)

Equity in losses of unconsolidated affiliates		(91	)		(1	)		(90	)		—			(1	)
Operating income		1,120			2,875			(1,755	)		3,046			(171	)

Other income and (deductions)
Interest expense		(301	)		(170	)		(131	)		(153	)		(17	)
Other, net		239			122			117			257			(135	)

Total other income and (deductions)		(62	)		(48	)		(14	)		104			(152	)

Income before income taxes		1,058			2,827			(1,769	)		3,150			(323	)
Income taxes		500			1,056			556			1,178			122

Net income		558			1,771			(1,213	)		1,972			(201	)
Net loss attributable to noncontrolling interest		(4	)		—			(4	)		—			—

Net income on common stock	$	562		$	1,771		$	(1,209	)	$	1,972		$	(201	)

(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.

(b)	Includes the operations of Constellation from the date of the merger, March 12, 2012, through December 31, 2012.

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Net Income

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. Generation’s net income decreased compared to the same period in 2011 primarily due to higher operating expenses, the loss on the sale of Brandon Shores, Wagner and C.P. Crane (collectively Maryland generating stations) and the amortization of acquired energy contracts recorded at fair value at the merger date; offset by higher revenues, net of purchased power and fuel expense and favorable NDT fund performance. The increase in operating expenses was due to the addition of Constellation’s financial results from March 12, 2012, costs related to a 2012 settlement with FERC and transaction and employee-related severance costs associated with the merger. The increase in revenues, net of purchased power and fuel expense was also primarily due to the merger. See Note 4 for additional information regarding the loss on the sale of three Maryland generating stations.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. Generation’s net income decreased compared to the same period in 2010 primarily due to mark-to-market losses on economic hedging activities and higher operating and maintenance expenses. Generation’s 2011 results were further affected by increased nuclear fuel costs, less favorable NDT fund performance in 2011 and higher nuclear refueling outage costs associated with the increased number of refueling outage days in 2011. These unfavorable impacts were partially offset by higher revenues due to the expiration of the PECO PPA on December 31, 2010 and favorable market and portfolio conditions in the ERCOT region.

Revenue Net of Purchased Power and Fuel Expense

Generation’s six reportable segments are based on the geographic location of its assets, and are largely representative of the footprints of an ISO/RTO and/or NERC region. Descriptions of each of Generation’s six reportable segments are as follows:

•

Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina.

•

Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the entire United States footprint of MISO, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

•

New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•

New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•

ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

•

Other Regions not considered individually significant:

•

South represents operations in the FRCC and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

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•

West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.

•

Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO.

The following business activities are not allocated to a region, and are reported under Other: retail and wholesale gas, investments in natural gas exploration and production activities, proprietary trading, energy efficiency and demand response, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems. Further, the following activities are not allocated to a region, and are reported in Other: compensation under the reliability-must-run rate schedule; results of operations from the Maryland Clean-Coal assets sold in Q4 2012; unrealized mark-to-market impact of economic hedging activities; amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger; and other miscellaneous revenues.

Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power and fuel expense which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for internally generated energy and fuel costs associated with tolling agreements.

For the year ended December 31, 2012 compared to 2011 and 2011 compared to 2010, Generation’s revenue net of purchased power and fuel expense by region were as follows:


							2012 vs. 2011									2011 vs. 2010
	2012 ^(a)			2011			Variance			% Change			2010			Variance			% Change
Mid-Atlantic ^(b)^(f)	$	3,433		$	3,350		$	83			2.5	%	$	2,501		$	849			33.9	%
Midwest ^(c)		2,998			3,547			(549	)		(15.5	)%		4,081			(534	)		(13.1	)%
New England		196			9			187			n.m.			11			(2	)		n.m.
New York ^(f)		76			—			76			n.m.			—			—			n.m.
ERCOT		405			84			321			n.m.			(65	)		149			n.m.
Other Regions ^(d)		131			(14	)		145			n.m.			(66	)		52			n.m.

Total electric revenue net of purchased power and fuel expense	$	7,239		$	6,976		$	263			3.8	%	$	6,462		$	514			8.0	%
Proprietary Trading		(14	)		24			(38	)		n.m.			27			(3	)		(11.1	)%
Mark-to-market gains (losses)		515			(288	)		803			n.m.			86			(374	)		n.m.
Other ^(e)		(364	)		146			(510	)		n.m.			(13	)		159			n.m.

Total revenue net of purchased power and fuel expense	$	7,376		$	6,858		$	518			7.6	%	$	6,562		$	296			4.5	%

(a)	Includes results for Constellation business transferred to Generation beginning on March 12, 2012, the date the merger was completed.

(b)	Results of transactions with PECO and BGE are included in the Mid-Atlantic region.

(c)	Results of transactions with ComEd are included in the Midwest region.

(d)	Other Regions includes South, West and Canada, which are not considered individually significant.

(e)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at merger date of $1,098 million pre-tax for the twelve months ended December 31, 2012.

(f)	Includes $487 million and $306 million of purchase power from CENG in the Mid-Atlantic and New York regions, respectively. See Note 22 of the Combined Notes to Consolidated Financial Statements for additional information.

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Generation’s supply sources by region are summarized below:


					2012 vs. 2011							2011 vs. 2010
Supply source (GWh)	2012 ^(a)		2011		Variance		% Change			2010		Variance			% Change
Nuclear generation ^(b)
Mid-Atlantic		47,337		47,287		50		0.1	%		47,517		(230	)		(0.5	)%
Midwest		92,525		92,010		515		0.6	%		92,493		(483	)		(0.5	)%

		139,862		139,297		565		0.4	%		140,010		(713	)		(0.5	)%

Fossil and renewables ^(b)
Mid-Atlantic ^(b)(d)		8,808		7,572		1,236		16.3	%		9,426		(1,854	)		(19.7	)%
Midwest		971		596		375		62.9	%		68		528			n.m.
New England		9,965		8		9,957		n.m.			10		(2	)		(20.0	)%
ERCOT ^(e)		6,182		2,030		4,152		n.m.			1,129		901			79.8	%
Other Regions ^(f)		5,913		1,432		4,481		n.m.			84		1,348			n.m.

		31,839		11,638		20,201		n.m.			10,717		921			8.6	%

Purchased power
Mid-Atlantic ^(c)		20,830		2,898		17,932		n.m.			1,918		980			51.1	%
Midwest		9,805		5,970		3,835		64.2	%		7,032		(1,062	)		(15.1	)%
New England		9,273		—		9,273		n.m.			—		—			n.m.
New York ^(c)		11,457		—		11,457		n.m.			—		—			n.m.
ERCOT ^(e)		23,302		7,537		15,765		n.m.			9,494		(1,957	)		(20.6	)%
Other Regions ^(f)		17,327		2,503		14,824		n.m.			2,618		(115	)		(4.4	)%

		91,994		18,908		73,086		n.m.			21,062		(2,154	)		(10.2	)%

Total supply by region ^(g)
Mid-Atlantic ^(h)		76,975		57,757		19,218		33.3	%		58,861		(1,104	)		(1.9	)%
Midwest ⁽ⁱ⁾		103,301		98,576		4,725		4.8	%		99,593		(1,017	)		(1.0	)%
New England		19,238		8		19,230		n.m.			10		(2	)		n.m.
New York		11,457		—		11,457		n.m.			—		—			n.m.
ERCOT		29,484		9,567		19,917		n.m.			10,623		(1,056	)		(9.9	)%
Other Regions ^(f)		23,240		3,935		19,305		n.m.			2,702		1,233			45.6	%

Total supply		263,695		169,843		93,852		55.3	%		171,789		(1,946	)		(1.1	)%

(a)	Includes results for Constellation business transferred to Generation beginning on March 12, 2012, the date the merger was completed.

(b)	Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(c)	Purchased power includes physical volumes of 9,925 GWh in the Mid-Atlantic and 9,350 GWh in New York as a result of the PPA with CENG for the year ended December 31, 2012.

(d)	Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 as a result of the Exelon and Constellation merger.

(e)	Generation from Wolf Hollow is included in purchased power through the acquisition date of August 24, 2011, and included within Fossil and Renewables subsequent to the acquisition date.

(f)	Other Regions includes South, West and Canada, which are not considered individually significant.

(g)	Excludes physical proprietary trading volumes of 12,958 GWh, 5,742 GWh and 3,625 GWh for the years ended December 31, 2012, 2011 and 2010 respectively.

(h)	Includes sales to PECO through the competitive procurement process of 7,762 GWh, 7,041 GWh, and 42,003 GWh for the years ended December 31, 2012, 2011 and 2010 respectively. Sales to BGE of 3,766 GWh were included for the year ended December 31, 2012.

(i)	Includes sales to ComEd under the RFP procurement of 4,152 GWh, 4,731 GWh and 8,218 GWh for the years ended December 31, 2012, 2011 and 2010 respectively.

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The following table presents electric revenue net of purchased power and fuel expense per MWh of electricity sold during the year ended December 31, 2012 as compared to the same period in 2011 and 2011 as compared to the same period in 2010.


						2012 vs. 2011						2011 vs. 2010
$/MWh	2012 ^(a)		2011			% Change			2010			% Change
Mid-Atlantic ^(b)	$	44.60	$	58.00			(23.1	)%	$	42.48			36.5	%
Midwest ^(c)		29.02		35.99			(19.4	)%		40.98			(12.2	)%
New England		10.19		n.m.			n.m.			—			n.m.
New York		6.63		n.m.			n.m.			—			n.m.
ERCOT		13.74		8.78			56.5	%		(6.24	)		n.m.
Other Regions ^(d)		5.64		(3.56	)		n.m.			(23.97	)		85.1	%
Electric revenue net of purchased power and fuel expense per MWh ^(e)(f)	$	27.45	$	41.07			(33.2	)%	$	37.62			9.2	%

(a)	Includes financial results for Constellation business transferred to Generation beginning on March 12, 2012, the date the merger was completed.

(b)

Includes sales to PECO of $536 million (7,762 GWh), $508 million (7,041 GWh) and $2,091 million (42,003 GWh) for the years ended December 31, 2012, 2011 and 2010, respectively. Sales to BGE of $322 million (3,766 GWH) were included for the year ended December 31, 2012. Excludes compensation under the reliability-must-run rate schedule and the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the merger.

(c)	Includes sales to ComEd of $162 million (4,152 GWh), $179 million (4,731 GWh) and $288 million (8,218 GWhs) and settlements of the ComEd swap of $627 million, $474 million and $385 million for years ended December 31, 2012, 2011 and 2010, respectively.

(d)	Other Regions includes South, West and Canada, which are not considered individually significant.

(e)	Revenue net of purchased power and fuel expense per MWh represents the average margin per MWh of electricity sold during the years ended December 31, 2012, 2011 and 2010, respectively, and excludes the mark-to-market impact of Generation’s economic hedging activities.

(f)

Excludes retail gas activity, proprietary trading portfolio activity, compensation under the reliability-must-run rate schedule and fuel sales. Also excludes results from energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities. In addition, excludes the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the Exelon and Constellation merger. Also excludes amortization of intangible assets relating to commodity contracts recorded at fair value at the merger date.

Mid-Atlantic

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The increase in revenue net of purchased power and fuel expense in the Mid-Atlantic of $83 million was primarily due to the addition of Constellation in 2012 and higher capacity revenues, partially offset by lower realized power prices and increased nuclear fuel costs.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The $849 million increase in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to increased margins on the volumes previously sold under Generation’s PPA with PECO, which expired on December 31, 2010, partially offset by increased nuclear fuel costs.

Midwest

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The decrease in revenue net of purchased power and fuel expense in the Midwest of $549 million was primarily due to lower capacity revenues, increased nuclear fuel costs, and lower realized power prices, partially offset by decreased congestion costs.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The $534 million decrease in revenue net of purchased power and fuel expense in the Midwest was primarily due to

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decreased realized margins in 2011 for the volumes previously sold by Generation under the 2006 ComEd auction contracts and increased nuclear fuel costs. These decreases were partially offset by increased capacity revenues, favorable settlements under the ComEd swap and the additional revenue following the acquisition of Exelon Wind in December 2010.

New England

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The $187 million increase in revenue net of purchased power and fuel expense in New England was as a result of the Constellation merger. Prior to the merger, New England was not a significant contributor to revenue net of purchased power and fuel expense at Generation.

New York

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The $76 million increase in revenue net of purchased power and fuel expense in New York was as a result of the Constellation merger. Prior to the merger, New York was not a significant contributor to revenue net of purchased power and fuel expense at Generation.

ERCOT

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The $321 million increase in revenue net of purchased power and fuel expense in ERCOT was primarily as a result of the Constellation merger, partially offset by a decrease in revenue net of purchased power and fuel expense in the legacy Generation ERCOT portfolio driven by the performance of Generation’s generating units during extreme weather events that occurred in Texas in February and August 2011.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The $149 million increase in revenue net of purchased power and fuel expense in the ERCOT was primarily driven by the performance of Generation’s generating units during extreme weather events that occurred in Texas in February and August 2011.

Other Regions

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The $145 million increase in revenue net of purchased power and fuel expense in Other Regions was primarily as a result of the Constellation merger.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The $52 million increase in revenue net of purchased power and fuel expense in Other Regions was due to the impact of additional revenue from the acquisition of Exelon Wind in December 2010, as well as higher margins due to overall favourable market conditions.

Mark-to-market

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. 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 economic hedging activities were $515 million in 2012 compared to losses of $288 million in 2011. 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.

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. 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 losses on economic hedging activities were $288 million in 2011 compared to gains of $86 million in 2010. 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.

Other

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The $510 million decrease in other revenue net of purchased power and fuel was primarily due to the amortization of the acquired energy contracts recorded at fair value at the merger date. This decrease was partially offset by results from activities acquired as part of the merger including retail gas, energy efficiency, energy management and demand response, upstream natural gas and the design and construction of renewable energy facilities. In addition, other revenue net of purchased power and fuel includes the results of Brandon Shores, H.A. Wagner and C.P. Crane, the generating facilities divested in Q4 as a result of the Exelon and Constellation merger. See Note 4 of the Combined Notes to Consolidated Financial Statements for information regarding contract intangibles and assets planned for divestiture as a result of the Constellation merger.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The $159 million increase in other revenue net of purchased power and fuel was primarily due the impacts of the impairment charge of certain emissions allowances recognized in 2010, additional other wholesale fuel sales in 2011 as well as compensation under the reliability-must-run rate schedule further described in Note 15 of the Combined Notes to Consolidated Financial Statements.

Nuclear Fleet Capacity Factor and Production Costs

The following table presents nuclear fleet operating data for 2012, as compared to 2011 and 2010, 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.


	2012			2011			2010
Nuclear fleet capacity factor ^(a)		92.7	%		93.3	%		93.9	%
Nuclear fleet production cost per MWh ^(a)	$	19.50		$	18.86		$	17.31

(a)	Excludes Salem, which is operated by PSEG Nuclear, LLC, and CENG’s nuclear facilities, which are operated by CENG. Reflects ownership percentage of stations operated by Exelon.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The nuclear fleet capacity factor, which excludes Salem, decreased primarily due to a higher number of non-refueling outage days, partially offset by a lower number of planned refueling outage days in 2012. For 2012 and 2011, planned refueling outage days totaled 274 and 283, respectively, and non-refueling outage days totaled 73 and 52, respectively. Higher nuclear fuel costs resulted in a higher production cost per MWh during 2012 as compared to 2011.

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The nuclear fleet capacity factor, which excludes Salem, decreased primarily due to a higher number of planned refueling outage days. For 2011 and 2010, planned refueling outage days totaled 283 and 261, respectively. Lower generation, higher nuclear fuel costs and higher plant operating and maintenance costs resulted in a higher production cost per MWh during 2011 as compared to 2010.

Operating and Maintenance Expense

The changes in operating and maintenance expense for 2012 compared to 2011, consisted of the following:


	Increase (Decrease)
Labor, other benefits, contracting and materials	$	845
Loss on the sale of Maryland Clean Coal assets ^(a)		278
FERC settlement ^(b)		195
Constellation merger and integration costs		182
Corporate allocations ^(c)		175
Pension and non-pension postretirement benefits expense		76
Maryland commitments ^(d)		35
Nuclear refueling outage costs, including the co-owned Salem plant ^(e)		(52	)
Other		146

Increase in operating and maintenance expense	$	1,880

(a)

Represents expense recorded during the third quarter of 2012 due to the reduction in book value. Upon completion of the November 30, 2012 transaction, Generation recorded a $6 million gain within Other, net in its Consolidated Statements of Operations and Comprehensive Income. The net loss on the sale of the Maryland Clean Coal assets was $272 million. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

(b)	Reflects costs incurred as part of a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.

(c)	Reflects an increased share of corporate allocated costs due to the merger.

(d)	Reflects costs incurred as part of the Maryland order approving the merger.

(e)	Reflects the impact of decreased planned refueling outages during 2012.

The changes in operating and maintenance expense for 2011 compared to 2010, consisted of the following:


	Increase (Decrease)
Labor, other benefits, contracting and materials	$	113
Nuclear refueling outage costs, including the co-owned Salem Plant ^(a)		74
Exelon Wind ^(b)		39
Asset retirement obligation reduction ^(c)		28
2010 nuclear insurance credit ^(d)		20
Corporate allocations ^(e)		19
Acquisition costs ^(f)		14
Other ^(g)		29

Increase in operating and maintenance expense	$	336

(a)	Reflects the impact of increased planned refueling outages during 2011.

(b)	Includes $30 million in 2011 associated with labor, other benefits, contracting and materials at Exelon Wind.

(c)	Reflects an increase in Generation’s decommissioning obligation for spent fuel at Zion station. See Note 13 of the Combined Notes to Consolidated Financial Statements for further information.

(d)	Reflects the impact of the return of property and business interruption insurance premiums in 2010. No premiums were returned for 2011.

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(e)	Primarily reflects increased lobbying costs related to EPA and competitive market matters.

(f)	Reflects increase in certain costs associated with the acquisitions of Constellation, Exelon Wind, Wolf Hollow and Antelope Valley incurred in 2011. See Note 4 of the Combined Notes to Consolidated Financial Statements for further information.

(g)	Includes additional environmental remediation costs recorded during 2011.

Depreciation and Amortization

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The increase in depreciation and amortization expense was primarily a result of higher plant balances due to the addition of Constellation facilities; and capital additions and other upgrades to legacy plants.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The increase in depreciation and amortization expense was primarily a result of higher plant balances due to the acquisition of Exelon Wind, capital additions and other upgrades to existing facilities. Higher plant balances resulted in an increase in depreciation and amortization expense of $61 million. The remaining increase in depreciation and amortization expense was due to the impact of increases in asset retirement costs (ARC) for Generation’s nuclear generating facilities.

Taxes Other Than Income

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The increase was primarily due to the addition of Constellation’s financial results in 2012.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The increase was primarily due to increased gross receipt taxes related to retail sales in the Mid-Atlantic region. These gross receipt taxes are recovered in revenue, and as a result, have no impact to Generation’s results of operations.

Equity in Losses of Unconsolidated Affiliates

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. Equity in losses of unconsolidated affiliates in 2012 primarily reflected $172 million related to the amortization of the basis difference in CENG recorded at fair value at the merger date, partially offset by $73 million of net income generated from Exelon’s equity investment in CENG.

Interest Expense

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The increase in interest expense is primarily due to the increase in long-term debt as a result of the merger.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The increase in interest expense is primarily due to debt issuances in 2010, further described in Note 11 of the Combined Notes to Consolidated Financial Statements. The increase in long-term debt resulted in higher interest expense of approximately $27 million.

Other, Net

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The increase in other, net primarily reflects net realized and unrealized gains related to the NDT funds of Generation’s Non-Regulatory Agreement Units compared to net realized and unrealized losses in 2011, as described in the table below. Additionally, the increase reflects $117 million and $18 million of income in 2012 and 2011, respectively, related to the contractual elimination of income tax expense associated with the NDT funds of the Regulatory Agreement Units, $85 million of credit facility termination fees

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recorded in 2012, a $36 million bargain purchase gain associated with the August 2011 acquisition of Wolf Hollow and the impact of a $32 million one-time interest income from the NDT fund special transfer tax deduction in 2011.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The decrease in other, net primarily reflects net unrealized losses in 2011 related to the NDT funds of Generation’s Non-Regulatory Agreement Units compared to net unrealized gains in 2010, as described in the table below. Additionally, the decrease reflects the contractual elimination of $18 million of income tax expense associated with the NDT funds of the Regulatory Agreement Units in 2011 compared to the contractual elimination of $96 million of income tax expense in 2010. These decreases are partially offset by the $32 million impact of one-time interest income from the NDT fund special transfer tax deduction recognized in 2011 and a $36 million bargain purchase gain associated with the August 2011 acquisition of Wolf Hollow.

The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in other, net for 2012, 2011 and 2010:


	2012		2011			2010
Net unrealized gains (losses) on decommissioning trust funds	$	105	$	(4	)	$	104
Net realized gains (losses) on sale of decommissioning trust funds	$	51	$	(10	)	$	2

Effective Income Tax Rate.

Generation’s effective income tax rates for the years ended December 31, 2012, 2011 and 2010 were 47.3%, 37.4% and 37.4%, respectively. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Results of Operations—ComEd


	2012			2011			Favorable (unfavorable) 2012 vs. 2011 variance			2010			Favorable (unfavorable) 2011 vs. 2010 variance
Operating revenues	$	5,443		$	6,056		$	(613	)	$	6,204		$	(148	)
Purchased power expense		2,307			3,035			728			3,307			272

Revenue net of purchased power expense ^(a)		3,136			3,021			115			2,897			124

Other operating expenses
Operating and maintenance		1,345			1,189			(156	)		1,069			(120	)
Depreciation and amortization		610			554			(56	)		516			(38	)
Taxes other than income		295			296			1			256			(40	)

Total other operating expenses		2,250			2,039			(211	)		1,841			(198	)

Operating income		886			982			(96	)		1,056			(74	)

Other income and (deductions)
Interest expense, net		(307	)		(345	)		38			(386	)		41
Other, net		39			29			10			24			5

Total other income and (deductions)		(268	)		(316	)		48			(362	)		46

Income before income taxes		618			666			(48	)		694			(28	)
Income taxes		239			250			11			357			107

Net income	$	379		$	416		$	(37	)	$	337		$	79

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(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, 2012, Compared to Year Ended December 31, 2011. ComEd’s net income for the year ended December 31, 2012, was lower than the same period in 2011 primarily due to lower electric distribution rates, effective June 20, 2012, pursuant to the ICC Order in the initial formula filing under EIMA. Offsetting the impact of the lower rates were increases in revenue resulting from the annual reconciliation of ComEd’s distribution revenue requirement pursuant to EIMA, net of lower allowed return on equity. Additionally, offsetting the impacts of lower electric distribution rates was increased transmission revenue during 2012. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

The increase in operating and maintenance expenses reflect increases in contracting and labor expenses as a result of the first year of the ten-year grid modernization project related to EIMA. Operating and maintenance costs also increased as a result of increased pension and other non-pension and postretirement benefits expenses due to the impact of lower actuarially assumed discount rates and expected return on plan assets for 2012 as compared to 2011. Additionally, operating and maintenance costs were higher in 2012 due to one-time net benefits recognized in 2011 pursuant to the May 2011 ICC order in ComEd’s 2010 rate case.

Year Ended December 31, 2011, Compared to Year Ended December 31, 2010. The increase in ComEd’s net income was primarily due to higher electric distribution rates, effective June 1, 2011, pursuant to the ICC order in the 2010 Rate Case, and increased revenues resulting from the annual reconciliation of ComEd’s distribution revenue requirement pursuant to EIMA, which became effective in the fourth quarter of 2011. Net income was also higher due to the re-measurement of uncertain income tax positions in 2010 related to the 1999 sale of ComEd’s fossil generating assets. The re-measurement resulted in increased interest expense and income tax expense recorded in 2010. These increases to net income were partially offset by higher operating and maintenance expense and taxes other than income.

The increase in operating and maintenance expense reflects the benefit recorded in 2010 resulting from the ICC’s approval of ComEd’s uncollectible accounts expense rider mechanism, a reduction in ComEd’s ARO reserve in 2010, and higher labor and contracting expenses incurred in 2011. These increases to operating and maintenance expense were partially offset by one-time net benefits recognized pursuant to the ICC order in ComEd’s 2010 rate case.

Operating Revenues and 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 3 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electricity procurement process.

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Electric revenues and purchased power expense are affected by fluctuations in customers’ purchases from competitive electric generation suppliers. All ComEd customers have the ability to purchase electricity from an alternative electric generation supplier. The customer choice of electric generation supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation services. The number of retail customers purchasing electricity from competitive electric generation suppliers was 1,627,150 and 380,262 at December 31, 2012, and 2011, respectively, representing 43% and 10% of total retail customers, respectively. Retail deliveries purchased from competitive electric generation suppliers represented 65% and 56% of ComEd’s retail kWh sales at December 31, 2012, and 2011, respectively. On March 20, 2012, approximately 170 Illinois municipalities approved referenda regarding electric supply aggregation. This approval allowed municipal officials to identify and sign contracts with alternative retail electric suppliers. With few exceptions, these municipalities have identified and switched to alternative retail electric suppliers as of December 31, 2012. The City of Chicago and approximately 70 other municipalities and townships passed similar referenda in November 2012. The City of Chicago switching will occur in the first quarter of 2013. All or some of the other 70 municipalities and townships are also expected to switch during the first half of 2013. As contracts with new retail electric suppliers take effect, ComEd expects the percentage of retail deliveries purchased from retail electric suppliers to continue to increase. It is anticipated that by the end of the second quarter 2013 approximately 72% of retail customers and 82% of kWh sales in the ComEd region will be supplied by competitive retail electric suppliers.

The changes in ComEd’s electric revenue net of purchased power expense for 2012 compared to 2011 consisted of the following:


	Increase (Decrease)
Electric distribution revenues	$	40
Transmission		40
Regulatory required programs cost recovery		32
Revenues subject to refund, net		4
Weather delivery		2
Volume delivery		(4	)
Other		1

Total increase	$	115

Electric distribution revenues

In 2011, the ICC issued an order in the 2010 Rate Case approving an increase in ComEd’s annual revenue requirement. The order became effective June 1, 2011, resulting in higher revenues for the first six months ended June 30, 2012, compared to the same period in 2011. Offsetting this increase was the lower rates which went into effect June 20, 2012, resulting from the May Order issued in ComEd’s 2011 formula rate proceeding under EIMA. Additionally, electric distribution revenues increased as a result of the annual reconciliation of ComEd’s distribution revenue requirement pursuant to EIMA. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission

ComEd’s transmission rates are established based on a FERC-approved formula. ComEd’s most recent annual formula rate update, filed in May 2012, reflects actual 2011 expenses and investments plus forecasted 2012 capital additions. Transmission revenues net of purchased power expense vary from year to year based upon fluctuations in the underlying costs, investments being recovered and

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other billing determinants, such as the highest daily peak load from the previous calendar year. ComEd set a record for the highest daily peak load of 23,753 MWs on July 20, 2011, which was reflected in the determination of transmission revenues billed beginning January 1, 2012, and transmission rates that went into effect on June 1, 2012. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory required programs cost recovery

Revenues related to regulatory required programs are the recoveries from customers for costs of various legislative and/or regulatory programs on a full and current basis through approved regulated rates. Programs include ComEd’s energy efficiency and demand response and purchased power administrative costs. An equal and offsetting amount has been reflected in operating and maintenance expense during the periods presented. Refer to the operating and maintenance expense discussion below for additional information on included programs.

Revenues subject to refund, net

ComEd records revenues subject to refund based upon its best estimate of customer collections that may be required to be refunded. During the year ended December 31, 2012, ComEd did not record material revenues subject to refund associated with any matters. As a result of the September 30, 2010, Illinois Appellate Court (Court) decision in the 2007 Rate Case which ruled against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via Rider SMP, ComEd began recording revenue subject to refund prospectively. In addition, ComEd began recording revenue subject to refund on June 1, 2010, relating to the recovery of Cash Working Capital (CWC) through its energy procurement rider. Based on the 2010 Rate Case order as well as the order on remand associated with the Court order, during the third quarter 2011 ComEd reduced its revenue subject to refund reserve. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information on these proceedings.

Weather—delivery

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. The favorable weather conditions for the year ended December 31, 2012, resulted in an increase in revenues net of purchased power expense.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd’s service territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the years ended December 31, 2012, and 2011, consisted of the following:


							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Twelve Months Ended December 31,
Heating Degree-Days		5,065		6,134		6,341		(17.4	)%		(20.1	)%
Cooling Degree-Days		1,324		1,036		842		27.8	%		57.2	%

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Volume—delivery

Revenues net of purchased power expense decreased as a result of lower delivery volume, exclusive of the effects of weather, reflecting decreased average usage per residential customer for 2012, compared to 2011.

Other

Other revenues were higher during the year ended December 31, 2012, compared to 2011. Other revenues, which can vary period to period, include rental revenues, revenues related to late payment charges, assistance provided to other utilities through mutual assistance programs, recoveries of environmental costs associated with MGP sites and recoveries under ComEd’s uncollectible accounts tariff.

The changes in ComEd’s electric revenue net of purchased power expense for 2011 compared to 2010 consisted of the following:


	Increase (Decrease)
Pricing (2010 Rate Case)	$	89
Revenues subject to refund, net		31
Distribution formula rate reconciliation		29
Regulatory required programs cost recovery		21
Transmission		18
2007 City of Chicago settlement		2
Volume—delivery		(10	)
Weather—delivery		(21	)
Uncollectible accounts recovery, net		(33	)
Other		(2	)

Total increase	$	124

Pricing (2010 Rate Case)

The ICC issued an order in the 2010 Rate Case approving an increase in ComEd’s annual electric distribution revenue requirement. The order became effective June 1, 2011, resulting in higher revenues for the year ended December 31, 2011, compared to the same period in 2010. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Revenues subject to refund, net

As a result of the September 30, 2010, Court decision in the 2007 Rate Case ComEd began recording revenue subject to refund prospectively. In addition, ComEd began recording revenue subject to refund on June 1, 2010, relating to the recovery of Cash Working Capital (CWC) through its energy procurement rider. As a result of the 2010 rate case order, ComEd reduced its revenue subject to refund reserve during the third quarter of 2011. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Distribution formula rate reconciliation

EIMA provides for a performance-based formula rate tariff. The legislation provides for an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. ComEd made its initial reconciliation filing in May

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2012 and the adjusted rates will take effect in January 2013. At December 31, 2011, ComEd had recorded an estimated reconciliation of approximately $29 million which did not include the reconciliation of significant storm costs discussed under operating and maintenance expense below. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory required programs cost recovery

Revenues related to regulatory required programs are the recoveries from customers of costs for various legislative and/or regulatory programs on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating and maintenance for regulatory required programs during the period presented. See Note 3 of the Combined Notes to Financial Statements for additional information.

Transmission

ComEd’s transmission rates are established based on a FERC-approved formula. ComEd’s 2010 formula rate update, filed in May 2011, reflects actual 2010 expenses and investments plus forecasted 2011 capital additions. Transmission revenues net of purchased power expense vary from year to year based upon fluctuations in the underlying costs and investments being recovered.

2007 City of Chicago Settlement

ComEd paid $1 million and $3 million in 2011 and 2010, respectively, under the terms of its 2007 settlement agreement with the City of Chicago. Payments were recorded as a reduction to revenues; therefore, the lower payment in 2011 resulted in a net increase in revenues net of purchased power expense for 2011 compared to 2010.

Volume—delivery

Weather—delivery

The increase in revenues net of purchased power expense in 2011 compared to 2010 were partially offset by unfavorable weather conditions, despite setting a new record for highest daily peak load of 23,753 MWs on July 20, 2011.

The changes in heating and cooling degree days in ComEd’s service territory consisted of the following:


							% Change
Heating and Cooling Degree-Days	2011		2010		Normal		From 2010			From Normal
Twelve Months Ended December 31,
Heating Degree-Days		6,134		5,991		6,362		2.4	%		(3.6	)%
Cooling Degree-Days		1,036		1,181		855		(12.3	)%		21.2	%

Uncollectible accounts recovery, net

Represents recoveries under ComEd’s uncollectible accounts tariff. Refer to uncollectible accounts expense discussion below for further information.

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Operating and Maintenance Expense


	Year Ended December 31,				Increase		Year Ended December 31,				Increase
	2012		2011		2012 vs. 2011		2011		2010		2011 vs. 2010
Operating and maintenance expense—baseline	$	1,198	$	1,074	$	124	$	1,074	$	975	$	99
Operating and maintenance expense—regulatory required programs ^(a)		147		115		32		115		94		21

Total operating and maintenance expense	$	1,345	$	1,189	$	156	$	1,189	$	1,069	$	120

(a)	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 approved regulated rates. An equal and offsetting amount has been reflected in operating revenues.

The changes in operating and maintenance expense for year ended December 31, 2012, compared to the same period in 2011 and changes for the year ended December 31, 2011, compared to the same period in 2010, consisted of the following:


	Increase (Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
Baseline
Labor, other benefits, contracting and materials^(b)	$	95		$	72
Pension and non-pension postretirement benefits expense		46			1
Discrete impacts from 2010 Rate Case order^(a)		32			(32	)
Corporate Allocations		—			8
Storm Related Costs ^(d)		(1	)		2
Technology Innovation Trust ^(d)		(11	)		15
Uncollectible accounts expense—one-time impact of 2010 ICC Order ^(c)		—			60
Uncollectible accounts expense, net ^(c)		(27	)		(33	)
Other		(10	)		6

		124			99
Regulatory required programs
Energy efficiency and demand response programs		33			25
Purchased power administrative costs		(1	)		(4	)

		32			21

Increase in operating and maintenance expense	$	156		$	120

(a)	In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time net benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan.

(b)	The increase in 2012 labor, other benefits, contracting and material costs is the result of the first year of a ten year grid modernization project associated with EIMA. See Note 3 of the Combined Notes to the Financial Statements for additional information.

(c)

On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with Illinois legislation providing public utilities the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism starting with 2008 and prospectively. As a result of this order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense for the cumulative under-collections in 2008 and 2009. In addition, ComEd recorded a onetime contribution of $10 million associated with this legislation.

(d)

Under EIMA, ComEd may recover costs associated with certain one-time events, such as large storms, over a five-year period. During the fourth quarter of 2011, ComEd recorded a net reduction in operating and maintenance expense for costs related to three significant 2011 storms. In addition, pursuant to EIMA, ComEd makes recurring payments for contribution to a Science and Technology Innovation Trust fund that will be used to fund energy innovation.

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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 approved regulated rates. An equal and offsetting amount has been reflected in operating revenues. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Depreciation and Amortization Expense

The changes in depreciation and amortization expense for 2012 compared to 2011 and 2011 compared to 2010, consisted of the following:


	Increase 2012 vs. 2011		Increase (Decrease) 2011 vs. 2010
Depreciation expense associated with higher plant balances ^(a)	$	22	$	20
Storm Cost Amortization		4		14
Other Regulatory Asset Amortization		14		(2	)
Other		16		6

Increase in depreciation and amortization expense	$	56	$	38

Taxes Other Than Income

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. Taxes other than income taxes decreased primarily due to decreased Illinois electricity distribution taxes. Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes, and payroll taxes.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. Taxes other than income taxes increased primarily due to the accrual of estimated future refunds of Illinois utility distribution tax recorded in 2010 for the 2008 and 2009 tax years. Previously, ComEd had recorded refunds of the Illinois utility distribution tax when received. Due to sufficient, reliable evidence, ComEd began in June 2010 recording an estimated receivable associated with anticipated Illinois utility distribution tax refunds prospectively.

Interest Expense, Net

The changes in interest expense, net for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	(Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
Interest expense related to uncertain tax positions ^(a)	$	—		$	(63	)
Interest expense on debt (including financing trusts) ^(b)		(26	)		20
Other		(12	)		2

Decrease in interest expense, net	$	(38	)	$	(41	)

(a)	During 2010, ComEd recorded $59 million of interest expense associated with the re-measurement of uncertain income tax positions related to the 1999 sale of Fossil Generating Assets.

(b)	Interest expense on debt decreased in 2012 due to more favorable interest rates on long-term debt balances year over year.

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Other, Net

The changes in other, net for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	Increase (Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
Interest income related to uncertain tax positions	$	16		$	8
Other		(6	)		(3	)

Increase in Other, net	$	10		$	5

Effective Income Tax Rate

ComEd’s effective income tax rate for the years ended December 31, 2012, 2011, and 2010 was 38.7%, 37.5% and 51.4%, respectively. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.


Retail Deliveries to customers (in GWhs)	2012		2011		% Change 2012 vs 2011			Weather- Normal % Change			2010		% Change 2011 vs 2010			Weather- Normal % Change
Retail Delivery and Sales ^(a)
Residential		28,528		28,273		0.9	%		(0.6	)%		29,171		(3.1	)%		(1.3	)%
Small commercial & industrial		32,534		32,281		0.8	%		0.2	%		32,904		(1.9	)%		(0.8	)%
Large commercial & industrial		27,643		27,732		(0.3	)%		(0.3	)%		27,717		0.1	%		0.6	%
Street Lighting & electric railroads		1,272		1,235		3.0	%		4.2	%		1,273		(3.0	)%		(1.2	)%

Total Retail		89,977		89,521		0.5	%		(0.1	)%		91,065		(1.7	)%		(0.5	)%


	As of December 31,
Number of Electric Customers	2012		2011		2010
Residential		3,455,546		3,448,481		3,438,677
Small commercial & industrial		365,357		365,824		363,393
Large commercial & industrial		1,980		2,032		2,005
Street Lighting & electric railroads		4,812		4,797		5,078

Total		3,827,695		3,821,134		3,809,153


Electric Revenue	2012		2011		% Change 2012 vs 2011			2010		% Change 2011 vs 2010
Retail Delivery and Sales ^(a)
Residential	$	3,037	$	3,510		(13.5	)%	$	3,549		(1.1	)%
Small commercial & industrial		1,339		1,517		(11.7	)%		1,639		(7.4	)%
Large commercial & industrial		395		383		3.1	%		397		(3.5	)%
Street Lighting & electric railroads		44		50		(12.0	)%		62		(19.4	)%

Total Retail		4,815		5,460		(11.8	)%		5,647		(3.3	)%

Other Revenue ^(b)		628		596		5.4	%		557		7.0	%

Total Electric Revenues	$	5,443	$	6,056		(10.1	)%	$	6,204		(2.4	)%

(a)

Reflects delivery revenues and volumes from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier. All customers are assessed charges for delivery. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.

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(b)	Other revenue primarily includes transmission revenue from PJM. Other items include rental revenue, 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.

Results of Operations—PECO


	2012			2011			Favorable (unfavorable) 2012 vs. 2011 variance			2010			Favorable (unfavorable) 2011 vs. 2010 variance
Operating revenues	$	3,186		$	3,720		$	(534	)	$	5,519		$	(1,799	)
Purchased power and fuel		1,375			1,864			489			2,762			898

Revenue net of purchased power and fuel expense ^(a)		1,811			1,856			(45	)		2,757			(901	)

Other operating expenses
Operating and maintenance		809			794			(15	)		733			(61	)
Depreciation and amortization		217			202			(15	)		1,060			858
Taxes other than income		162			205			43			303			98

Total other operating expenses		1,188			1,201			13			2,096			895

Operating income		623			655			(32	)		661			(6	)

Other income and (deductions)
Interest expense, net		(123	)		(134	)		11			(193	)		59
Other, net		8			14			(6	)		8			6

Total other income and (deductions)		(115	)		(120	)		5			(185	)		65

Income before income taxes		508			535			(27	)		476			59
Income taxes		127			146			19			152			6

Net income		381			389			(8	)		324			65
Preferred security dividends		4			4			—			4			—

Net income on common stock	$	377		$	385		$	(8	)	$	320		$	65

(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, 2012 Compared to Year Ended December 31, 2011. The decrease in net income was driven primarily by lower operating revenue net of purchased power and fuel expense and increased storm costs. The decrease in revenue net of purchased power and fuel expense was primarily related to unfavorable weather and a decline in electric load. The decrease to net income was partially offset by lower taxes other than income, interest expense and income taxes.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The increase in net income was primarily driven by new distribution rates effective January 1, 2011 as a result of the 2010 electric and natural gas rate case settlements, decreased interest expense and decreased income tax expense. The increase in net income was partially offset by increased storm costs, increased depreciation expense and the net impact of the 2010 CTC recoveries reflected in electric operating revenues net of purchased power expense and CTC amortization expense, both of which ceased at the end of the transition period on December 31, 2010.

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Operating Revenues Net of Purchased Power and Fuel Expense

There are certain drivers to operating revenue that are offset by their impact on purchased power and fuel expense, such as commodity procurement costs and customer choice programs. PECO’s electric generation rates charged to customers were capped until December 31, 2010 in accordance with the 1998 restructuring settlement. Beginning January 1, 2011, PECO’s electric generation rates are based on actual costs incurred through its approved competitive market procurement process. Electric and gas revenues and purchased power and fuel expenses are affected by fluctuations in commodity procurement costs. PECO’s electric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly and are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and gas revenues net of purchased power and fuel expenses.

Electric and gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the customer choice program. All PECO customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers, respectively. The customer’s choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and gas revenue net of purchase power and fuel expense. The number of retail customers purchasing energy from a competitive electric generation supplier was 496,500, 387,600 and 36,600 at December 31, 2012, 2011 and 2010, respectively. Retail deliveries purchased from competitive electric generation suppliers represented 66%, 57% and 1% of PECO’s retail kWh sales for the years ended December 31, 2012, 2011 and 2010, respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplier was 53,600, 24,800 and 6,800 at December 31, 2012, 2011 and 2010, respectively. Retail deliveries purchased from competitive natural gas suppliers represented 16%, 11% and 7% of PECO’s mmcf sales for the years ended December 31, 2012, 2011 and 2010, respectively.

The changes in PECO’s operating revenues net of purchased power and fuel expense for the year ended December 31, 2012 compared to the same period in 2011 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Weather	$	(17	)	$	(15	)	$	(32	)
Volume		(22	)		—			(22	)
Pricing		(4	)		3			(1	)
Regulatory required programs		29			—			29
Other		(19	)		—			(19	)

Total decrease	$	(33	)	$	(12	)	$	(45	)

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 and gas revenues net of purchased power and fuel expense were lower due to unfavorable winter weather conditions during 2012 in PECO’s service territory.

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Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the year ended December 31, 2012 compared to the same period in 2011 and normal weather consisted of the following:


							% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Twelve Months Ended December 31,
Heating Degree-Days		3,747		4,157		4,603		(9.9	)%		(18.6	)%
Cooling Degree-Days		1,603		1,617		1,301		(0.9	)%		23.2	%

Volume

The decrease in electric revenues net of purchased power expense related to delivery volume, exclusive of the effects of weather, reflected the reduced oil refinery load in PECO’s service territory and the impact of energy efficiency initiatives and weak economic conditions on customer usage. The decrease was partially offset by additional volumes due to the extra day from the leap year. See Note 3 of the Combined Notes to Consolidated Financial Statements for further information regarding energy efficiency initiatives.

Pricing

The decrease in operating revenues net of purchased power and fuel expense as a result of pricing reflects the refund of the tax cash benefit resulting from the adoption of the safe harbor method of tax accounting for electric distribution property in 2011. The refund was reflected on customer bills as a credit beginning January 1, 2012. The accounting impact of the refund is completely offset by regulatory liability amortization recorded in income tax expense. The decrease in operating revenues net of purchase power and fuel expense as a result of pricing was partially offset by higher overall effective rates due to decreased usage per customer across all customer classes.

Regulatory Required Programs

This represents the change in operating revenues collected under approved riders to recover costs incurred for the smart meter, energy efficiency and consumer education programs as well as the administrative costs for the GSA and AEPS programs. The riders are designed to provide full and current cost recovery as well as a return. The offsetting costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.

Other

The decrease in other electric revenues net of purchased power expense primarily reflected a decrease in GRT revenue as a result of lower supplied energy service and a reduction in the GRT rate. There is an equal and offsetting decrease in GRT expense included in taxes other than income.

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The changes in PECO’s operating revenues net of purchased power and fuel expense for the year ended December 31, 2011 compared to the same period in 2010 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Weather	$	(33	)	$	(13	)	$	(46	)
Volume		(11	)		3			(8	)
CTC recoveries		(995	)		—			(995	)
Pricing		139			16			155
Regulatory required programs		17			—			17
Other		(29	)		5			(24	)

Total increase (decrease)	$	(912	)	$	11		$	(901	)

Weather

Electric and gas revenues net of purchased power and fuel expense were lower due to unfavorable weather conditions during 2011 in PECO’s service territory compared to 2010 despite setting a new record for highest electric peak load of 8,983 MWs on July 22, 2011.

The changes in heating and cooling degree days for the twelve months ended 2011 and 2010, consisted of the following:


							% Change
Heating and Cooling Degree-Days ^(a)	2011		2010		Normal		From 2010			From Normal
Twelve Months Ended December 31,
Heating Degree-Days		4,157		4,396		4,638		(5.4	)%		(10.4	)%
Cooling Degree-Days		1,617		1,817		1,292		(11.0	)%		25.2	%

Volume

The decrease in electric revenues net of purchased power expense related to delivery volume, exclusive of the effects of weather, reflected weak economic growth, the impact of energy efficiency initiatives on customer usage and the ramp-down of two oil refineries. See Note 3 of the Combined Notes to the Consolidated Financial Statements for further information regarding energy efficiency initiatives.

The increase in gas revenues net of fuel expense related to delivery volume, exclusive of the effects of weather, reflected increased usage per customer across all customer classes.

CTC Recoveries

The decrease in electric revenues net of purchased power expense related to CTC recoveries reflected the absence of the CTC charge component that was included in rates charged to customers in 2010. PECO fully recovered all stranded costs during the final year of the transition period that expired on December 31, 2010.

Pricing

The increase in operating revenues net of purchased power and fuel expense as a result of pricing primarily reflected an increase of new electric and natural gas distribution rates charged to customers that became effective in January 1, 2011 in accordance with the 2010 PAPUC approved electric and natural gas distribution rate case settlements. See Note 3 of the Combined Notes to the Consolidated Financial Statements for further information.

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Regulatory Required Programs

Other

The decrease in electric revenues net of purchased power expense primarily reflected a decrease in GRT revenue as a result of lower supplied energy service and retail transmission revenue earned by PECO due to increased participation in the customer choice program. There is an equal and offsetting decrease in GRT expense included in taxes other than income. This decrease was partially offset by an increase in wholesale transmission revenue earned by PECO as a transmission owner for the use of PECO’s transmission facilities in PJM. The rates charged for wholesale transmission are based on the prior year’s peak, and the peak in 2010 was higher than in 2009.

The increase in gas operating revenues net of fuel expense primarily reflected an increase in off-system gas sales activity. Off-system gas sales revenues represent sales of excess gas supply on the wholesale market and the release of pipeline capacity.

Operating and Maintenance Expense


	Twelve Months Ended December 31,				Increase (Decrease) 2012 vs. 2011			Twelve Months Ended December 31,				Increase (Decrease) 2011 vs. 2010
	2012		2011		Increase (Decrease) 2012 vs. 2011			2011		2010		Increase (Decrease) 2011 vs. 2010
Operating and Maintenance Expense—Baseline	$	723	$	725	$	(2	)	$	725	$	680	$	45
Operating and Maintenance Expense—Regulatory
Required Programs ^(a)		86		69		17			69		53		16

Total Operating and Maintenance Expense	$	809	$	794	$	15		$	794	$	733	$	61

(a)	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 approved regulated rates. An equal and offsetting amount has been reflected in operating revenues.

132

The changes in operating and maintenance expense for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	Increase (Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
Baseline
Labor, other benefits, contracting and materials	$	(29	)	$	26
Storm-related costs		9	^(a)		13
Uncollectible accounts expense		(4	)		4
Constellation merger and integration costs		15			2
2010 non-cash charge resulting from Health Care Legislation		—			(2	)
Other		7			2

		(2	)		45

Regulatory Required Programs
Smart Meter		12			9
Energy Efficiency		8			2
GSA		(1	)		5
Consumer education program		(1	)		(1	)
AEPS		(1	)		1

		17			16

Increase in operating and maintenance expense	$	15		$	61

(a)	Storm-related costs include $46 million of incremental storm costs incurred in the fourth quarter of 2012 as a result of Hurricane Sandy. This expense was significantly offset by the costs incurred related to Hurricane Irene and other storms throughout 2011.

Depreciation and Amortization Expense

The changes in depreciation and amortization expense for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	Increase (Decrease) 2012 vs. 2011		Increase (Decrease) 2011 vs. 2010
CTC amortization^(a)	$	—	$	(885	)
Other ^(b)		15		27

Increase (decrease) in depreciation and amortization expense	$	15	$	(858	)

(a)	PECO’s scheduled CTC amortization was recorded in accordance with its 1998 restructuring settlement and was fully amortized as of December 31, 2010.

(b)	Increase due primarily to ongoing capital expenditures.

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Taxes Other Than Income

The change in taxes other than income for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	Increase (Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
GRT expense ^(a)	$	(33	)	$	(97	)
Sales and use tax		(12	)^(b)		—
PURTA amortization		—			(4	)^(c)
Other		2			3

Decrease in taxes other than income	$	(43	)	$	(98	)

(a)	The decrease in GRT expense for 2012 compared to 2011 and 2011 compared to 2010 was a result of lower operating revenues. In addition, there was a reduction in the GRT rate in 2012.

(b)	The decrease reflects a sales and use tax reserve adjustment in the first quarter of 2012 resulting from the completion of the audit of tax years 2005 through 2010.

(c)	The decrease in taxes other than income related to PURTA amortization reflects the impact of regulatory liability amortization recorded in 2011 that offsets the distribution rate reduction made to refund a 2009 PURTA Supplemental Tax settlement to customers.

Interest Expense, Net

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The decrease in interest expense, net for 2012 compared to 2011 was primarily due to the debt retirement in November 2011.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The decrease in interest expense, net for 2011 compared to 2010 was primarily due to the retirement of PETT transition bonds on September 1, 2010 and the impact of interest expense incurred in June 2010 related to the change in measurement of uncertain tax positions in accordance with accounting guidance.

See Notes 1 and 12 of the Combined Notes to Consolidated Financial Statements for further information.

Other, Net

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The decrease in Other, net for 2012 compared to 2011 was due to decreased AFUDC—Equity. See Note 20 of the Combined Notes to Consolidated Financial Statements for additional details of the components of Other, net.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The increase in Other, net for 2011 compared to 2010 was primarily due to increased investment income and AFUDC Equity. See Note 20 of the Combined Notes to Consolidated Financial Statements for further information.

Effective Income Tax Rate

PECO’s effective income tax rates for the years ended December 31, 2012, 2011 and 2010 were 25.0%, 27.3% and 31.9%, respectively. The effective income tax rate for the year ended December 31, 2012 reflects the impact of the tax benefit received from electing to change the method of accounting for gas distribution property for the 2011 tax year. Comparatively, the effective income tax rate for the

134

year ended December 31, 2011 includes the effect of electing the safe harbor method of tax accounting for electric distribution property for the 2010 tax year. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO Electric Operating Statistics and Revenue Detail


Retail Deliveries to customers (in GWhs)	2012		2011		% Change 2012 vs. 2011			Weather- Normal % Change			2010		% Change 2011 vs. 2010			Weather- Normal % Change
Retail Delivery and Sales ^(a)
Residential		13,233		13,687		(3.3	)%		(1.7	)%		13,913		(1.6	)%		1.7	%
Small commercial & industrial		8,063		8,321		(3.1	)%		(2.3	)%		8,503		(2.1	)%		(0.7	)%
Large commercial & industrial		15,253		15,677		(2.7	)%		(2.7	)%		16,372		(4.2	)%		(3.3	)%
Public authorities & electric railroads		943		945		(0.2	)%		(0.2	)%		925		2.2	%		4.6	%

Total Electric Retail		37,492		38,630		(2.9	)%		(2.2	)%		39,713		(2.7	)%		(0.9	)%


	As of December 31,
Number of Electric Customers	2012		2011		2010
Residential		1,417,773		1,415,681		1,411,643
Small commercial & industrial		148,803		148,570		148,297
Large commercial & industrial		3,111		3,110		3,071
Public authorities & electric railroads		9,660		9,689		9,670

Total		1,579,347		1,577,050		1,572,681


Electric Revenue	2012		2011		% Change 2012 vs. 2011			2010		% Change 2011 vs. 2010
Retail Delivery and Sales ^(a)
Residential	$	1,689	$	1,934		(12.7	)%	$	2,069		(6.5	)%
Small commercial & industrial		462		585		(21.0	)%		1,061		(44.9	)%
Large commercial & industrial		232		308		(24.7	)%		1,364		(77.4	)%
Public authorities & electric railroads		31		38		(18.4	)%		89		(57.3	)%

Total Retail		2,414		2,865		(15.7	)%		4,583		(37.5	)%

Other Revenue ^(b)		226		244		(7.4	)%		252		(3.2	)%

Total Electric Revenues	$	2,640	$	3,109		(15.1	)%	$	4,835		(35.7	)%

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

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PECO Gas Operating Statistics and Revenue Detail


Deliveries to customers (in mmcf)	2012		2011		% Change 2012 vs. 2011			Weather- Normal % Change			2010		% Change 2011 vs. 2010			Weather- Normal % Change
Retail Delivery and Sales ^(b)
Retail sales		49,767		54,239		(8.2	)%		(0.1	)%		56,833		(4.6	)%		1.2	%
Transportation and other		26,687		28,204		(5.4	)%		(4.8	)%		30,911		(8.8	)%		(7.5	)%

Total Gas Deliveries		76,454		82,443		(7.3	)%		(1.6	)%		87,744		(6.0	)%		(1.8	)%


	As of December 31,
Number of Gas Customers	2012		2011		2010
Residential		454,502		451,382		448,391
Commercial & industrial		41,836		41,373		41,303

Total Retail		496,338		492,755		489,694
Transportation		903		879		838

Total		497,241		493,634		490,532


Gas revenue	2012		2011		% Change 2012 vs. 2011			2010		% Change 2011 vs. 2010
Retail Delivery and Sales ^(a)
Retail sales	$	509	$	576		(11.6	)%	$	657		(12.3	)%
Transportation and other		37		35		5.7	%		27		29.6	%

Total Gas Deliveries	$	546	$	611		(10.6	)%	$	684		(10.7	)%

(a)

Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

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Results of Operations—BGE


	2012			2011			Favorable (unfavorable) 2012 vs. 2011 variance			2010			Favorable (unfavorable) 2011 vs. 2010 variance
Operating revenues	$	2,735		$	3,068		$	(333	)	$	3,541		$	(473	)
Purchased power and fuel expense		1,369			1,593			224			2,147			554

Revenue net of purchased power and fuel expense ^(a)		1,366			1,475			(109	)		1,394			81

Other operating expenses
Operating and maintenance		728			680			(48	)		595			(85	)
Depreciation and amortization		298			274			(24	)		249			(25	)
Taxes other than income		208			207			(1	)		200			(7	)

Total other operating expenses		1,234			1,161			(73	)		1,044			(117	)

Operating income		132			314			(182	)		350			(36	)

Other income and (deductions)
Interest expense, net		(144	)		(129	)		(15	)		(131	)		2
Other, net		23			26			(3	)		25			1

Total other income and (deductions)		(121	)		(103	)		(18	)		(106	)		3

Income before income taxes		11			211			(200	)		244			(33	)
Income taxes		7			75			68			97			22

Net income		4			136			(132	)		147			(11	)
Preference stock dividends		13			13			—			13			—

Net (loss) income on common stock	$	(9	)	$	123		$	(132	)	$	134		$	(11	)

(a)

BGE 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. BGE believes revenue net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power and 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, 2012 Compared to Year Ended December 31, 2011. The decrease in net income was driven primarily by decreased operating revenue net of purchased power and fuel expense related to the residential customer rate credit provided as a condition of the MDPSC’s approval of Exelon’s merger with Constellation. The decrease in net income was also driven by increased operating and maintenance expenses, primarily related to BGE’s accrual of its portion of the charitable contributions to be provided as a condition of the MDPSC’s approval of the merger as well as merger transaction costs, and increased depreciation and amortization expense. None of the customer rate credit, the charitable contributions, or the transaction costs are recoverable from BGE’s customers.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The decrease in net income was primarily driven by increased storm costs, increased depreciation and amortization expense and increased merger transaction costs. Partially offsetting these unfavorable impacts were increased operating revenues primarily driven by new distribution rates as a result of the 2010 Maryland PSC rate order. None of the transaction costs are recoverable from BGE’s customers.

137

Operating Revenues Net of Purchased Power and Fuel Expense

There are certain drivers to operating revenue that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.

The number of customers electing to select a competitive EGS affects electric SOS revenues and purchased power expense. The number of customers electing to select a competitive NGS affects gas cost adjustment revenues and purchased natural gas expense. All BGE customers have the choice to purchase energy from a competitive EGS. This customer choice of EGSs does not impact the volume of deliveries, but affects revenue collected from customers related to SOS. The number of retail customers purchasing electricity from a competitive EGS was 362,000, 314,000 and 228,000 at December 31, 2012, 2011 and 2010, respectively, representing 29%, 25% and 18% of total retail customers, respectively. Retail deliveries purchased from competitive EGSs represented 60%, 58% and 50% of BGE’s retail kWh sales for the years ended December 31, 2012, 2011 and 2010, respectively. The number of retail customers purchasing natural gas from a competitive NGS was 143,000, 118,000 and 84,000 at December 31, 2012, 2011 and 2010, respectively, representing 22%, 18% and 13% of total retail customers, respectively. Retail deliveries purchased from competitive NGSs represented 56%, 52% and 49% of BGE’s retail mmcf sales for the years ended December 31, 2012, 2011 and 2010, respectively.

The changes in BGE’s operating revenues net of purchased power and fuel expense for the year ended December 31, 2012 compared to the same period in 2011 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Residential customer rate credit ^(a)	$	(82	)	$	(31	)	$	(113	)
Commodity margin		(1	)		(5	)		(6	)
Regulatory program cost recovery		15			4			19
Transmission		11			—			11
Other		(13	)		(7	)		(20	)

Total decrease	$	(70	)	$	(39	)	$	(109	)

(a)

In accordance with the MDPSC order approving Exelon’s merger with Constellation, the residential customer rate credit is not recoverable from BGE’s customers. Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.

Revenue Decoupling. The demand for electricity and gas is affected by weather and usage conditions. The MDPSC has allowed BGE to record a monthly adjustment to its electric and gas distribution revenues from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’s electric and gas distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This allows BGE to recognize revenues at MDPSC-approved levels per customer, regardless of what BGE’s actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. BGE bills or credits impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

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Volume. Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE’s service territory. The changes in heating degree days in BGE’s service territory for the year ended December 31, 2012 compared to the same period in 2011 and normal weather consisted of the following:


Heating and Cooling Degree-Days	2012		2011		Normal		% Change
Heating and Cooling Degree-Days	2012		2011		Normal		From 2011			From Normal
Twelve Months Ended December 31,
Heating Degree-Days		3,960		4,326		4,711		(8.5	)%		(15.9	)%
Cooling Degree-Days		1,022		1,035		858		(1.3	)%		19.1	%

Residential Customer Rate Credit

The residential customer rate credit provided as a result of the MDPSC’s order approving Exelon’s merger with Constellation decreased operating revenues net of purchased power and fuel expense for year ended December 31, 2012.

Commodity Margin

The commodity margin for both electric and gas revenues decreased during the year ended December 31, 2012 compared to the same period in 2011. Commodity revenues are affected by the number of customers using competitive suppliers as well as the cost of purchased power and natural gas.

Regulatory Required Programs

This represents the change in revenues collected under approved riders to recover costs incurred for the energy efficiency and demand response programs as well as administrative and commercial and industrial customer bad debt costs for SOS. The riders are designed to provide full recovery, as well as a return in certain instances. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and taxes other than income taxes. The increase in revenues during the year ended December 31, 2012 compared to the same period in 2011 was due to the recovery of higher energy efficiency program costs.

Transmission

Transmission revenues increased during the year ended December 31, 2012 compared to the same period in 2011. BGE’s transmission rates are established based on a FERC-approved formula. The rates also include transmission investment incentives approved by FERC in a number of orders covering various new transmission investment projects since 2007.

Other

Other revenues decreased during the year ended December 31, 2012 compared to the same period in 2011. Other revenues, which can vary from period to period, include miscellaneous revenues such as late payment charge revenues and all base distribution revenues, including the impact of revenue decoupling, which decreased due to lower volumes and customer mix.

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The changes in BGE’s operating revenues net of purchased power and fuel expense for the year ended December 31, 2011 compared to the same period in 2010 consisted of the following:


	Increase (Decrease)
	Electric			Gas		Total
Distribution rates increase	$	28		$	8	$	36
Commodity margin		(17	)		2		(15	)
Regulatory program cost recovery		20			1		21
Transmission		18			—		18
Other		16			5		21

Total increase	$	65		$	16	$	81

Volume

The changes in heating and cooling degree days for the twelve months ended 2011 and 2010, consisted of the following:


Heating and Cooling Degree-Days ^(a)	2011		2010		Normal		% Change
Heating and Cooling Degree-Days ^(a)	2011		2010		Normal		From 2010			From Normal
Twelve Months Ended December 31,
Heating Degree-Days		4,326		4,716		4,720		(8.3	)%		(8.3	)%
Cooling Degree-Days		1,035		1,122		853		(7.8	)%		21.3	%

Distribution Rates Increase

The MDPSC issued an order approving an increase in BGE’s annual electric distribution revenue requirement. The order became effective December 4, 2010, resulting in higher revenues for the year ended December 31, 2011 compared to the same period in 2010. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.

Commodity Margin

The commodity margin for electric revenues decreased during the year ended December 31, 2011 compared to the same period in 2010. Commodity revenues are affected by the number of customers using competitive suppliers as well as the cost of purchased power and natural gas. Additionally, the decrease is a result of the reinstatement of the credit for the residential return component of the administrative charge on June 1, 2010. This credit will continue through December 2016.

Regulatory Program Cost Recovery

The increase in electric revenues relating to regulatory program cost recovery was due to the recovery of higher energy efficiency program costs and demand response program costs. The costs of these programs are recoverable from customers on a full and current basis through approved regulated rates and have been reflected in operating and maintenance expense, depreciation and amortization expense and taxes other than income taxes.

Transmission

Transmission revenues increased during the year ended December 31, 2011 compared to the same period in 2010. BGE’s transmission rates are established based on a FERC-approved formula. The rates also include transmission investment incentives approved by FERC in a number of orders covering various new transmission investment projects since 2007.

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Other

Other revenues increased during the year ended December 31, 2011 compared to the same period in 2010. Other revenues, which can vary from period to period, include miscellaneous revenues such as late payment charge revenues and all other base distribution revenues, including the impact of revenue decoupling, which increased due to higher volumes and customer mix.

Operating and Maintenance Expense


	Twelve Months Ended December 31,				Increase (Decrease) 2012 vs. 2011			Twelve Months Ended December 31,				Increase (Decrease) 2011 vs. 2010
	2012		2011		Increase (Decrease) 2012 vs. 2011			2011		2010		Increase (Decrease) 2011 vs. 2010
Operating and Maintenance Expense—Baseline	$	728	$	679	$	49		$	679	$	591	$	88
Operating and Maintenance Expense—Regulatory Required Programs ^(a)		—		1		(1	)		1		4		(3	)

Total Operating and Maintenance Expense	$	728	$	680	$	48		$	680	$	595	$	85

(a)	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 approved regulated rates. An equal and offsetting amount has been reflected in operating revenues.

The changes in operating and maintenance expense for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	Increase (Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
Baseline
Charitable contributions ^(a)	$	28		$	—
Storm costs deferral ^(b)		16			(16	)
Storm-related costs ^(c)		7			41
Pension and non-pension postretirement benefits expense		6			2
Labor, other benefits, contracting and materials		(10	)		25
Merger transaction costs^(a)		(9	)		30
Uncollectible accounts expense		—			6
Other		11			—

		49			88
Regulatory Required Programs
SOS		(1	)		(3	)

		(1	)		(3	)

Increase in operating and maintenance expense	$	48		$	85

(a)	The charitable contribution accrual and merger transaction costs are not recoverable from BGE’s customers.

(b)	During the first quarter of 2011, the MDPSC issued a comprehensive rate order permitting the deferral of incremental distribution service restoration expenses associated with 2010 storms as a regulatory asset.

(c)

On June 29, 2012, a “Derecho” storm caused extensive damage to BGE’s electric distribution system and created power outages that lasted multiple days. As a result, BGE incurred $62 million of incremental costs during the year ended December 31, 2012, of which $20 million are capital costs. In the fourth quarter of 2012, BGE incurred $38 million of incremental costs as a result of Hurricane Sandy, of which $14 million are capital costs. These amounts compare to $40 million of incremental expenses incurred during the third quarter of 2011 associated with Hurricane Irene and $14 million of incremental expenses incurred during the first quarter of 2011.

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Depreciation and Amortization Expense

The changes in depreciation and amortization expense for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	Increase (Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
Depreciation expense^(a)		$20		$	10
Regulatory asset amortization		6			13
Other		(2	)		2

Increase in depreciation and amortization expense		$24		$	25

(a)	Depreciation and amortization expense increased due to higher plant balances year over year.

Taxes Other Than Income

The change in taxes other than income for 2012 compared to 2011 and 2011 compared to 2010 consisted of the following:


	Increase (Decrease) 2012 vs. 2011			Increase (Decrease) 2011 vs. 2010
Property tax	$	4		$	5
Other		(3	)		2

Increase in taxes other than income	$	1		$	7

Interest Expense, Net

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011. The increase in interest expense, net for 2012 compared to 2011 was primarily due to higher outstanding debt balances.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010. The change in interest expense, net in 2011 compared to 2010 was relatively flat.

Effective Income Tax Rate

BGE’s effective income tax rates for the years ended December 31, 2012, 2011 and 2010 were 63.6%, 35.5% and 39.8%, respectively. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE Electric Operating Statistics and Revenue Detail


Retail Deliveries to customers (in GWhs)	2012		2011		% Change 2012 vs. 2011			Weather- Normal % Change		2010		% Change 2011 vs. 2010			Weather- Normal % Change
Retail Delivery and Sales ^(a)
Residential		12,719		12,652		0.5	%		n.m.		13,834		(8.5	)%		n.m.
Small commercial & industrial		15,943		16,276		(2.0	)%		n.m.		16,040		1.5	%		n.m.
Large commercial & industrial		1,980		2,464		(19.6	)%		n.m.		2,578		(4.4	)%		n.m.
Public authorities & electric railroads		329		405		(18.8	)%		n.m.		400		1.3	%		n.m.

Total Electric Retail		30,971		31,797		(2.6	)%		n.m.		32,852		(3.2	)%		n.m.


	As of December 31,
Number of Electric Customers	2012		2011		2010
Residential		1,116,233		1,116,401		1,114,712
Small commercial & industrial		119,122		118,568		118,250
Large commercial & industrial		5,452		5,823		5,534
Public authorities & electric railroads		319		326		326

Total		1,241,126		1,241,118		1,238,822


Electric Revenue	2012		2011		% Change 2012 vs. 2011			2010		% Change 2011 vs. 2010
Retail Delivery and Sales ^(a)
Residential	$	1,274	$	1,456		(12.5	)%	$	1,857		(21.6	)%
Small commercial & industrial		600		632		(5.1	)%		687		(8.0	)%
Large commercial & industrial		40		51		(21.6	)%		53		(3.8	)%
Public authorities & electric railroads		30		29		3.4	%		30		(3.3	)%

Total Retail		1,944		2,168		(10.3	)%		2,627		(17.5	)%

Other Revenue ^(b)		239		228		4.8	%		204		11.8	%

Total Electric Revenues	$	2,183	$	2,396		(8.9	)%	$	2,831		(15.4	)%

(a)

Reflects delivery revenues and volumes from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes wholesale transmission revenue and late payment charges.

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BGE Gas Operating Statistics and Revenue Detail


Deliveries to customers (in mmcf)	2012		2011		% Change 2012 vs. 2011			Weather- Normal % Change		2010		% Change 2011 vs. 2010			Weather- Normal % Change
Retail Delivery and Sales ^(c)
Retail sales		86,946		94,800		(8.3	)%		n.m.		98,928		(4.2	)%		n.m.
Transportation and other ^(d)		15,751		16,436		(4.2	)%		n.m.		14,711		11.7	%		n.m.

Total Gas Deliveries		102,697		111,236		(7.7	)%		n.m.		113,639		(2.1	)%		n.m.


	As of December 31,
Number of Gas Customers	2012		2011		2010
Residential		610,827		608,943		608,553
Commercial & industrial		44,228		44,211		44,041

Total		655,055		653,154		652,594


Gas revenue	2012		2011		% Change 2012 vs. 2011			2010		% Change 2011 vs. 2010
Retail Delivery and Sales ^(c)
Retail sales	$	494	$	580		(14.8	)%	$	620		(6.5	)%
Transportation and other ^(d)		58		92		(37.0	)%		90		2.2	%

Total Gas Deliveries	$	552	$	672		(17.9	)%	$	710		(5.4	)%

(c)

Reflects delivery revenues and volumes from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from BGE.

(d)	Transportation and other gas revenue includes off-system revenue of 15,751 mmcfs ($51 million), 16,436 mmcfs ($82 million) and 14,711 mmcfs ($80 million) for the years ended 2012, 2011 and 2010, respectively.

Liquidity and Capital Resources

Exelon and Generation activity presented below includes the activity of Constellation, and BGE in the case of Exelon, from the merger effective date of March 12, 2012 through December 31, 2012. Exelon and Generation activity for 2011 and 2010 is unadjusted for the effects of the merger. BGE activity presented below includes its activity for the 12 months ended December 31, 2012, 2011 and 2010.

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 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, PECO and BGE have access to unsecured revolving credit facilities with aggregate bank commitments of $0.5 billion, $5.3 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively. The Registrants’ revolving credit facilities are in place until 2017. In addition, Generation has a $0.3 billion bilateral facility with a bank. The bilateral facility at Generation has expirations in December 2015 and March 2016. The Registrant’s utilize their credit facilities to support their commercial paper programs, provide for other 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.

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The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit 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, PECO and BGE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 11 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 and energy-related products and services to 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, PECO’s and BGE’s cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO and BGE, gas distribution services. ComEd’s, PECO’s and BGE’s distribution services are provided to an established and diverse base of retail customers. ComEd’s, PECO’s and BGE’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, competitive suppliers, and their ability to achieve operating cost reductions.

See Notes 3 and 19 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.

Pension and Other Postretirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. Exelon expects to contribute approximately $270 million to its pension plans in 2013, of which Generation, ComEd, PECO and BGE expect to contribute $119 million, $117 million, $12 million and $2 million, respectively. See Note 14 of the Combined Notes to Consolidated Financial Statements for the Registrants’ 2012 and 2011 pension contributions.

Unlike the qualified pension plans, Exelon’s other postretirement plans are not subject to regulatory minimum contribution requirements. Management considers several factors in determining the level of contributions to Exelon’s other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued recovery). Exelon expects to contribute approximately $292 million to the other postretirement benefit plans in 2013, of which Generation, ComEd, PECO and BGE expect to contribute $117 million, $114 million, $22 million and $18 million, respectively. See Note 14 of the Combined Notes to Consolidated Financial Statements for the Registrants’ 2012 and 2011 other postretirement benefit contributions.

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See the “Contractual Obligations” section below for management’s estimated future pension and other postretirement benefits contributions.

Tax Matters

The Registrants’ future cash flows from operating activities may be affected by the following tax matters:

•

In November 2012, the IRS and Exelon finalized and executed definitive agreements to resolve Exelon’s involuntary conversion and CTC positions. Exelon expects that the IRS will assess approximately $300 million of tax and interest in the first quarter of 2013. In order to stop additional interest from accruing on the expected assessment, Exelon had previously made a payment in December 2010 to the IRS of $302 million. In addition Exelon, Generation, ComEd and PECO expect to receive tax refunds of approximately $375 million, $50 million, $350 million and $25 million, respectively, between 2013 and 2014, and the remainder paid by Exelon.

•

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.

•

In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The newly adopted method results in a cash tax benefit of approximately $38 million and $41 million at Exelon and PECO, respectively. Exelon currently anticipates that the IRS will issue industry guidance during 2013. See Note 3 of the Combined Notes to Consolidated Financial Statements for discussion regarding the regulatory treatment of PECO’s tax benefits from the application of the method change.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the years ended December 31, 2012, 2011 and 2010:


	2012			2011			2012 vs. 2011 Variance			2010			2011 vs. 2010 Variance
Net income	$	1,171		$	2,499		$	(1,328	)	$	2,563		$	(64	)
Add (subtract):
Non-cash operating activities ^(a)		5,588			4,848			740			4,340			508
Pension and non-pension postretirement benefit contributions		(462	)		(2,360	)		1,898			(959	)		(1,401	)
Income taxes		544			492			52			(543	)		1,035
Changes in working capital and other noncurrent assets and liabilities ^(b)		(731	)		(279	)		(452	)		122			(401	)
Option premiums paid, net		(114	)		(3	)		(111	)		(124	)		121
Counterparty collateral received (paid), net		135			(344	)		479			(155	)		(189	)

Net cash flows provided by operations	$	6,131		$	4,853		$	1,278		$	5,244		$	(391	)

(a)

Represents depreciation, amortization and accretion, mark-to-market gains and losses 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.

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Cash flows provided by operations for 2012, 2011 and 2010 by Registrant were as follows:


	2012		2011		2010
Exelon	$	6,131	$	4,853	$	5,244
Generation		3,581		3,313		3,032
ComEd		1,334		836		1,077
PECO		878		818		1,150
BGE		485		476		329

Changes in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’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 2012, 2011 and 2010 were as follows:

Generation

•

During 2012, 2011 and 2010, Generation had net (payments) receipts of counterparty collateral of $95 million, $(410) million and $(1) million, respectively. Net payments during 2012 and 2011 were primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position. Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with 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 $23 million in 2010. As of December 31, 2010, Generation had fulfilled its commitments under the Illinois Settlement Legislation.

•

During 2012, 2011 and 2010, Generation’s accounts receivable from ComEd increased (decreased) by $(15) million, $12 million and $(65) million, respectively, primarily due to changes in receivables for energy purchases related to its SFC, ICC-approved RFP contracts and financial swap contract.

•

During 2012, 2011 and 2010, Generation’s accounts receivable from PECO increased (decreased) by $17 million, $(210) million and $74 million, respectively.

•

During 2012, 2011 and 2010, Generation had net payments of approximately $114 million, $3 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 2012, 2011 and 2010, ComEd’s net payables to Generation for energy purchases related to its supplier forward contract, ICC-approved RFP contracts and financial swap contract settlements increased (decreased) by $(15) million, $12 million and $(65) million, respectively. During 2012, 2011 and 2010, ComEd’s payables to other energy suppliers for energy purchases increased (decreased) by $20 million, $(43) million and $58 million, respectively.

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•

During 2012 and 2011, ComEd received $37 million and $63 million, respectively, of incremental cash collateral from PJM due to variations in its energy transmission activity levels. As of December 31, 2012 and December 31, 2011, ComEd had $53 million and $90 million of cash collateral remaining at PJM.

PECO

•

During 2012, 2011 and 2010, PECO’s payables to Generation for energy purchases increased (decreased) by $17 million, $(210) million and $74 million, respectively, and payables to other energy suppliers for energy purchases increased (decreased) by $(22) million, $97 million and $1 million, respectively.

BGE

•

During 2012, 2011 and 2010, BGE’s payables to Generation for energy purchases increased (decreased) by $23 million, $(13) million and $0 million, respectively, and payables to other energy suppliers for energy purchases increased (decreased) by $40 million, $(60) million and $54 million, respectively. BGE’s increase in payables to other energy suppliers in 2010 is due to the implementation of the POR program during July 2010. The decrease in payables to other energy suppliers in 2011 is due to full payment to POR suppliers due to the implementation of a new customer billing system during January 2012.

Cash Flows from Investing Activities

Cash flows used in investing activities for 2012, 2011, and 2010 by Registrant were as follows:


	2012			2011			2010
Exelon ^(a)(b)(d)	$	(4,576	)	$	(4,603	)	$	(3,894	)
Generation ^(a)(d)		(2,629	)		(3,077	)		(2,896	)
ComEd		(1,212	)		(1,007	)		(939	)
PECO ^(b)		(328	)		(557	)		(120	)
BGE		(573	)		(592	)		(177	)

Capital expenditures by Registrant for 2012, 2011 and 2010 and projected amounts for 2013 are as follows:


	Projected 2013 ^(c)		2012		2011		2010
Generation ^(d)	$	2,850	$	3,554	$	2,491	$	1,883
ComEd ^(e)		1,400		1,246		1,028		962
PECO		569		422		481		545
BGE		663		582		592		508
Other ^(f)		43		67		42		(64	)

Total capital expenditures	$	5,525	$	5,871	$	4,634	$	3,834

(a)	Includes $387 million in 2011 related to acquisitions, principally acquisition of Wolf Hollow, Antelope Valley and Shooting Star; and $893 million in 2010, related to the acquisition of Exelon Wind. See Note 4 of the Combined Notes to Consolidated Financial Statements for additional information.

(b)	Includes a cash inflow of $413 million in 2010 as a result of the consolidation of PETT on January 1, 2010. See Note 1 of the Combined Notes to Consolidated Financial Statements for additional information.

(c)	Total projected capital expenditures do not include adjustments for non-cash activity.

(d)	Includes nuclear fuel.

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(e)

The projected capital expenditures include approximately $227 million of expected incremental spending. Pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten year period to modernize and storm-harden its distribution system and to implement smart grid technology. ComEd expects to file an updated investment plan with the ICC in April, 2013.

(f)	Other primarily consists of corporate operations and BSC. The negative capital expenditures for Other in 2010 primarily relate to the transfer of information technology hardware and software assets from BSC to Generation, ComEd and PECO.

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

Generation

Approximately 35% and 20% of the projected 2013 capital expenditures at Generation are for the acquisition of nuclear fuel; and investments in renewable energy generation, including Antelope Valley construction costs, respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Also included in the projected 2013 capital expenditures are a portion of the costs of a series of planned power uprates across Generation’s nuclear fleet. See “EXELON CORPORATION—Executive Overview,” for more information on nuclear uprates.

On November 30, 2012, a subsidiary of Generation sold three Maryland generating stations and associated assets to Raven Power Holdings LLC, a subsidiary of Riverstone Holdings LLC, and received net proceeds of approximately $371 million in the fourth quarter. In addition, Generation will make cash payments of approximately $32 million to Raven Power Holdings LLC over a twelve-month period beginning in June 2013. In 2012, Generation incurred transaction costs of approximately $15 million through the date of closing of the transaction. The sale will generate approximately $195 million of cash tax benefits, of which $155 million will be realized in periods through 2014 with the balance to be received in later years. Therefore, Generation expects net after-tax cash sale proceeds of approximately $495 million through 2014 and approximately $36 million in subsequent years.

ComEd, PECO and BGE

Approximately 89%, 89% and 77% of the projected 2013 capital expenditures at ComEd, PECO and BGE, respectively, are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA and ComEd’s, PECO’s and BGE’s construction commitments under PJM’s RTEP. In addition, this includes for ComEd capital expenditures related to smart grid/smart meter technology required under EIMA and for PECO and BGE capital expenditures related to its smart meter program and SGIG project, net of DOE expected reimbursements. The remaining amounts are for capital additions to support new business and customer growth. See Notes 3 and 6 of the Combined Notes to Consolidated Financial Statements for additional information.

As a result of the October 3, 2012 ICC Rehearing Order, ComEd currently plans to defer approximately $400 million of smart meter and other infrastructure spend from the period beginning 2012 through 2014 to 2015 and beyond. ComEd’s deferred approximately $65 million of planned spend in 2012.

In 2010, NERC provided guidance to transmission owners that recommends ComEd, PECO and BGE perform assessments of all their transmission lines, with the highest priority lines assessed by December 31, 2011, medium priority lines by December 31, 2012, and the lowest priority lines by December 31, 2013. In compliance with this guidance, ComEd, PECO and BGE submitted their most recent bi-annual reports to NERC in January 2013. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the

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assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 2013 capital expenditures above reflect capital spending for remediation to be completed in 2013.

ComEd, PECO and BGE anticipate that they will fund capital expenditures with internally generated funds and borrowings, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 3 of the Combined Notes to Consolidated Financial Statements.

Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for 2012, 2011 and 2010 by Registrant were as follows:


	2012			2011			2010
Exelon	$	(1,085	)	$	(846	)	$	(1,748	)
Generation		(777	)		(196	)		(779	)
ComEd		(212	)		355			(179	)
PECO		(382	)		(589	)		(811	)
BGE		128			115			(116	)

Debt. Debt activity for 2012, 2011 and 2010 by Registrant was as follows:


Company	Issuances of long-term debt in 2012	Use of proceeds
Generation	$78 million of variable rate CEU Credit Agreement project financing, due July 16, 2016	Used to fund Upstream gas activities

Generation	$220 million of fixed rate DOE Project Financing, due January 5, 2037	Used for Antelope Valley solar development

Generation	$523 million of 4.25% Senior Notes due June 15, 2022	Used for general corporate purposes and issued in connection with the Exchange Offer

Generation	$788 million of 5.60% Senior Notes due June 15, 2042	Used for general corporate purposes and issued in connection with the Exchange Offer

Generation	$38 million of variable rate Clean Horizons project financing due June 7, 2030	Used for funding for Maryland solar development

ComEd	$350 million of First Mortgage 3.80% Bonds, Series 113, due October 1, 2042	Used to repay outstanding commercial paper obligations and for general corporate purposes.

PECO	$350 million of First and Refunding Mortgage 2.38% Bonds due September 15, 2022	Used to pay at maturity First Mortgage Bonds due October 1, 2012 and for general corporate purposes

BGE	$250 million of fixed rate 2.80% Notes due August 15, 2022	Used to repay total outstanding commercial paper obligations and for general corporate purposes

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Company	Issuances of long-term debt in 2011	Use of proceeds
ComEd	$600 million of First Mortgage 1.625% Bonds, Series 110, due January 15, 2014	Used as an interim source of liquidity for a January 2011 contribution to Exelon-sponsored pension plans.

ComEd	$250 million of First Mortgage 1.95% Bonds, Series 111, due September 1, 2016	Used to retire $191 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 D, E, and F, $345 million of First Mortgage Bonds, Series 105, and for other general corporate purposes.

ComEd	$350 million of First Mortgage 3.40% Bonds, Series 112, due September 1, 2021	Used to retire $191 million tax-exempt variable-rate First Mortgage Bonds, Series 2008 D, E, and F, $345 million of First Mortgage Bonds, Series 105, and for other general corporate purposes.

BGE	$300 million of fixed rate 3.50% Notes, due November 15, 2021	Used to repay total outstanding commercial paper obligations and for general corporate purposes

Company	Issuances of long-term debt in 2010	Use of proceeds
Generation	$900 million of Senior Notes, consisting of $550 million Senior Notes, 4.00% due October 1, 2020 and $350 million Senior Notes, 5.75% due October 1, 2041	Used to finance the acquisition of Exelon Wind and for general corporate purposes.

ComEd	$500 million of First Mortgage Bonds at 4.00% due August 1, 2020	Used to refinance First Mortgage Bonds, Series 102, which matured on August 15, 2010 and for other general corporate purposes.


Company		Retirement of long-term debt in 2012
Exelon		$2 million of 7.30% fixed-rate Medium Term Notes with a maturity date of June 1, 2012.

Exelon		$442 million of 7.60% fixed-rate Senior Notes with a maturity date of April 1, 2032.

Generation		$2 million scheduled payments of 7.83% Kennett Square capital lease until September 20, 2020

Generation		$46 million of 3-year term rate Armstrong Co. 2009 A, Pollution Control Notes at 5.00% with a final maturity of December 1, 2042.

Generation		$89 million of variable rate project financing CEU Credit Agreement with a final maturity of July 16, 2016.

Generation		$17 million of variable rate Solar Revolver project financing with a final maturity of July 7, 2014.

Generation		$75 million of variable rate MEDCO tax-exempt bonds with a final maturity of April 1, 2024.

Generation		$2 million of variable rate Sacramento Solar Promissory Note with a final maturity of March 12, 2012.

ComEd		$450 million of 6.15% First Mortgage Bonds, Series 98, due March 15, 2012

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Company		Retirement of long-term debt in 2012
PECO		$225 million of 4.75% First and Refunding Mortgage Bonds, due October 1, 2012

PECO		$150 million of 4.00% First and Refunding Mortgage Bonds, due December 1, 2012

BGE		$8 million of 5.72% fixed rate Rate Stabilization Bonds, due April 1, 2016

BGE		$55 million of 5.47% fixed rate Rate Stabilization Bonds, due October 1, 2012

BGE		$110 million of variable rate Medium Term Notes, due June 15, 2012

Generation		$2 million scheduled payments of 7.83% Kennett Square capital lease until September 20, 2020

ComEd		$2 million of 4.75% sinking fund debentures, due December 1, 2011

ComEd		$50 million of tax-exempt variable-rate First Mortgage Bonds, Series 2008 D, due March 1, 2020

ComEd		$50 million of tax-exempt variable-rate First Mortgage Bonds, Series 2008 E, due May 1, 2021

ComEd		$91 million of tax-exempt variable-rate First Mortgage Bonds, Series 2008 F, due March 1, 2017

ComEd		$345 million of 5.40% First Mortgage Bonds, Series 105, due December 15, 2011

PECO		$250 million of 5.95% First and Refunding Mortgage Bonds, due November 1, 2011

BGE		$60 million of 5.47% fixed rate Rate Stabilization Bonds, due October 1, 2012

Company		Retirement of long-term debt in 2010
Exelon Corporate		$400 million of 4.45% 2005 Senior Notes, due June 15, 2010

Generation		$1 million scheduled payments of 7.83% Kennett Square capital lease until September 20, 2020

Generation		$13 million of Montgomery County Series 1994 B Tax Exempt Bonds with variable interest rates, due June 1, 2029

Generation		$17 million of Indiana County Series 2003 A Tax Exempt Bonds with variable interest rates, due June 1, 2027

Generation		$19 million of York County Series 1993 A Tax Exempt Bonds with variable interest rates, due August 1, 2016

Generation		$23 million of Salem County Series 1993 A Tax Exempt Bonds with variable interest rates, due March 1, 2025

Generation		$24 million of Delaware County Series 1993 A Tax Exempt Bonds with variable interest rates, due August 1, 2016

Generation		$34 million of Montgomery County Series 1996 A Tax Exempt Bonds with variable interest rates, due March 1, 2034

Generation		$83 million of Montgomery County Series 1994 A Tax Exempt Bonds with variable interest rates, due June 1, 2029

ComEd		$1 million of 4.75% sinking fund debentures, due December 1, 2011

ComEd		$212 million of 4.74% First Mortgage Bonds, due August 15, 2010

PECO		$806 million of 6.52% PETT Transition Bonds, due September 1, 2010

BGE		$57 million of 5.47% fixed rate Rate Stabilization Bonds, due October 1, 2012

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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 reduce debt on their respective balance sheets.

Dividends. Cash dividend payments and distributions during 2012, 2011 and 2010 by Registrant were as follows:


	2012		2011			2010
Exelon	$	1,733	$	1,393		$	1,389
Generation		1,626		172			1,508
ComEd		105		300			310
PECO		347		352			228
BGE		13		98	^(a)		13

(a)	Dividends on common stock for $85 million were paid to Constellation for the year ended December 31, 2011.

Revised Dividend Policy. On February 6, 2013, the Exelon Board of Directors approved a revised dividend policy which contemplates a regular $0.31 per share quarterly dividend on Exelon’s common stock payable beginning in the second quarter of 2013 (or $1.24 per share on an annualized basis), subject to quarterly declarations by the Exelon Board of Directors. The second quarter 2013 quarterly dividend of $0.31 per share on Exelon’s common stock is expected to be approved by the Exelon Board of Directors in the second quarter of 2013.

Short-Term Borrowings. Short-term borrowings incurred (repaid) during 2012, 2011 and 2010 by Registrant were as follows:


	2012			2011		2010
ComEd	$	—		$	—	$	(155	)
BGE		—			—		(46	)
Other ^(a)		(197	)		161		—

Exelon	$	(197	)	$	161	$	(201	)

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

Retirement of Long-Term Debt to Financing Affiliates. There were no retirement of long-term debt to financing affiliates during 2012, 2011 and 2010 by the Registrants.

Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during 2012, 2011 and 2010 by Registrant were as follows:


	2012		2011		2010
Generation	$	48	$	30	$	62
ComEd		11		11		2
PECO ^(a)		9		18		223
BGE		66		—		—

(a)	Reflects payment received to reduce the receivable from parent of $180 million for the year ended December 31, 2010 and was completely repaid as of December 31, 2010.

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Other. Other significant financing activities for Exelon for 2012, 2011 and 2010 were as follows:

•

Exelon received proceeds from employee stock plans of $72 million, $38 million and $48 million during 2012, 2011 and 2010, respectively.

Credit Matters

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 $8.3 billion in aggregate total commitments of which $3.8 billion was available as of December 31, 2012, and of which no financial institution has more than 10% of the aggregate commitments for Exelon, Generation, ComEd, PECO and BGE. The Registrants had access to the commercial paper market during 2012 to fund their short-term liquidity needs, when necessary. 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 flows from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of December 31, 2012, it would have been required to provide incremental collateral of approximately $1,920 million, which is well within its current available credit facility capacities of approximately $5.6 billion, which includes $1,920 million of collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements. If ComEd lost its investment grade credit rating as of December 31, 2012, it would have been required to provide incremental collateral of approximately $218 million, which is well within its current available credit facility capacity of approximately $1.0 billion. If PECO lost its investment grade credit rating as of December 31, 2012, it would not be required to provide collateral pursuant to PJM’s credit policy and could have been required to provide collateral of approximately $35 million related to its natural gas procurement contracts, which, in the aggregate, is well within PECO’s current available credit facility capacity of approximately $599 million. If BGE lost its investment grade credit rating as of December 31, 2012, it would have been required to provide collateral of $3 million pursuant to PJM’s credit policy and could have been required to provide collateral of approximately $124 million related to its natural gas procurement contracts, which, in the aggregate, is well within BGE’s current available credit facility capacity of approximately $600 million.

Exelon Credit Facilities

See Note 11 of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ credit facilities and short term borrowing activity.

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Other Credit Matters

Capital Structure. At December 31, 2012, the capital structures of the Registrants consisted of the following:


	Exelon			Generation			ComEd			PECO			BGE
Long-term debt		45	%		27	%		43	%		36	%		46	%
Long-term debt to affiliates ^(a)		2			10			2			3			5
Common equity		52			—			55			55			45
Member’s equity		—			63			—			—			—
Preferred securities		—			—			—			2			4
Commercial paper and notes payable		1			—			—			4			—

(a)

Includes approximately $648 million, $206 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd and PECO, respectively, and $258 million owed to a consolidated affiliate of BGE that all qualify as special purpose entities under the applicable authoritative guidance. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd, PECO and BGE. See Note 2 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. As a result of the ring-fencing measures required by the MDPSC, BGE does not participate in the intercompany money pool. 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 2012 are described in the following table in addition to the net contribution or borrowing as of December 31, 2012:


	Maximum Contributed		Maximum Borrowed		December 31, 2012 Contributed (Borrowed)
Generation	$	—	$	258	$	—
PECO		309		—		—
BSC		—		206		(119	)
Exelon Corporate		119		N/A		119

Shelf Registration Statements. The Registrants have combined a shelf registration statement with the SEC. As of December 31, 2012, that shelf registration statement remained effective and provides for the sale of unspecified amounts of securities. The ability of each Registrant to sell securities off that 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, PECO and BGE of long-term debt or equity securities requires the prior authorization of the ICC, PAPUC and MDPSC, respectively. ComEd, PECO and BGE 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. On February 27, 2012, ComEd received $1.3 billion in long-term debt refinancing authority from the ICC. As of December 31, 2012, ComEd had $1.4 billion available in long-term debt refinancing authority from the ICC and $106 million in new money long-term debt financing authority from the ICC. On October 24, 2012, the PAPUC approved PECO’s application for long-term financing authority for $2.5

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billion, which is effective through December 31, 2015. As of December 31, 2012, PECO had $1.9 billion available in long-term debt financing authority from the PAPUC. As of December 31, 2012, BGE had $1.2 billion available in long-term financing authority from MDPSC.

FERC has financing jurisdiction over ComEd’s, PECO’s and BGE’s short-term financings and all of Generation’s financings. As of December 31, 2012, ComEd and PECO had short-term financing authority from FERC that expires on December 31, 2013 of $2.5 billion and $1.5 billion, respectively. As of December 31, 2012, BGE had short-term financing authority from FERC that expires on December 31, 2014 of $0.7 billion. Generation currently has blanket financing authority that it received from FERC in connection with its market-based rate authority. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.

Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid 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. BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE’s preference stock have not been paid. At December 31, 2012, Exelon had retained earnings of $9,893 million, including Generation’s undistributed earnings of $3,168 million, ComEd’s retained earnings of $721 million consisting of retained earnings appropriated for future dividends of $2,360 million partially offset by $1,639 million of unappropriated retained deficit, PECO’s retained earnings of $593 million and BGE’s retained earnings $808 million. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding fund transfer restrictions.

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Contractual Obligations

The following tables summarize the Registrants’ future estimated cash payments as of December 31, 2012 under existing contractual obligations, including payments due by period. See Note 19 of the Combined Notes to Consolidated Financial Statements for information regarding the Registrants’ commercial and other commitments, representing commitments potentially triggered by future events.

Exelon


			Payment due within
	Total		2013		2014- 2015		2016- 2017		Due 2018 and beyond		All Other
Long-term debt ^(a)	$18,915		$	976	$	3,090	$	2,495	$	12,354	$	—
Interest payments on long-term debt^(b)		12,156		957		1,711		1,493		7,995		—
Liability and interest for uncertain tax positions^(c)		305		1		—		—		—		304
Capital leases		30		3		6		8		13		—
Operating leases^(d)		864		88		156		132		488		—
Purchase power obligations^(e)		3,516		1,246		1,313		483		474		—
Fuel purchase agreements ^(f)		9,955		1,554		2,764		2,208		3,429		—
Electric supply procurement ^(f)		1,721		741		703		277		—		—
AEC purchase commitments ^(f)		12		4		2		2		4		—
Curtailment services commitments ^(f)		153		49		88		16		—		—
Long-term renewable energy and
REC commitments^(g)		1,659		71		148		156		1,284		—
PJM regional transmission expansion commitments ^(h)		914		218		442		254		—		—
Spent nuclear fuel obligation		1,020		—		—		—		1,020		—
Pension minimum funding requirement⁽ⁱ⁾		2,223		255		599		923		446		—

Total contractual obligations	$	53,443	$	6,163	$	11,022	$	8,447	$	27,507	$	304

(a)	Includes $648 million due after 2016 to ComEd, PECO and BGE financing trusts.

(b)

Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2012 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, 2012. Includes estimated interest payments due to ComEd, PECO and BGE financing trusts.

(c)

As of December 31, 2012, Exelon’s liability for uncertain tax positions was $305 million. Exelon was unable to reasonably estimate the timing of liability and interest payments and receipts 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 12 of the Combined Notes to Consolidated Financial Statements for further information regarding unrecognized tax positions.

(d)	Excludes PPAs and other capacity contracts that are accounted for as operating leases. These amounts are included within purchase power obligations. Includes estimated cash payments for service fees related to PECO’s meter reading operating lease.

(e)

Purchase power obligations include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2012, including those related to CENG. 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 3 and 19 of the Combined Notes to Consolidated Financial Statements.

(f)

Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs and curtailment services. See Note 19 of the Combined Notes to Consolidated Financial Statements for electric and gas purchase commitments.

(g)	On December 17, 2010, ComEd entered into 20-year contracts with several unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. See Note 3 of Combined Notes to Consolidated Financial Statements for additional information.

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(h)

Under their operating agreements with PJM, ComEd, PECO and BGE are committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd’s, PECO’s and BGE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 of Combined Notes to Consolidated Financial Statements for additional information.

(i)

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 contributions necessary to avoid benefit restrictions and at-risk status. For Exelon’s largest qualified pension plan, the projected contributions reflect a funding strategy of contributing the greater of $250 million or the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contributions for years after 2018 are not included. See Note 14 of the Combined Notes to Consolidated Financial Statements for further information regarding estimated future pension benefit payments.

Generation


			Payment due within
	Total		2013		2014- 2015		2016- 2017		Due 2018 and beyond		All Other
Long-term debt	$	7,241	$	25	$	1,163	$	774	$	5,279	$	—
Interest payments on long-term debt^(a)		5,041		391		712		660		3,278		—
Liability and interest for uncertain tax benefits^(b)		236		—		—		—		—		236
Capital leases		30		3		6		8		13		—
Operating leases^(c)		553		38		76		72		367		—
Purchase power obligations^(d)		3,516		1,246		1,313		483		474		—
Fuel purchase agreements ^(e)		8,857		1,276		2,479		2,040		3,062		—
Spent nuclear fuel obligation		1,020		—		—		—		1,020		—

Total contractual obligations	$	26,494	$	2,979	$	5,749	$	4,037	$	13,493	$	236

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2012 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, 2012.

(b)

As of December 31, 2012, Generation’s liability for uncertain tax positions and related interest payable was $216 million and $20 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)	Excludes PPAs and other capacity contracts that are accounted for as operating leases. These amounts are included within purchase power obligations.

(d)

Purchase power obligations include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2012. 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 19 of the Combined Notes to Consolidated Financial Statements.

(e)	See Note 19 of the Combined Notes to Consolidated Financial Statements for further information regarding fuel purchase agreements.

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ComEd


			Payment due within
	Total		2013		2014- 2015		2016- 2017		Due 2018 and beyond		All Other
Long-term debt^(a)	$5,793		$	252	$	877	$	1,090	$	3,574	$	—
Interest payments on long-term debt^(b)		3,499		276		506		443		2,274		—
Liability and interest for uncertain tax positions^(c)		67		—		—		—		—		67
Operating leases		109		13		22		17		57		—
Electric supply procurement		1,103		367		459		277		—		—
Long-term renewable energy and associated REC commitments ^(d)		1,661		71		147		158		1,285		—
PJM regional transmission expansion commitments ^(e)		525		175		221		129		—		—

Total contractual obligations	$	12,757	$	1,154	$	2,232	$	2,114	$	7,190	$	67

(a)	Includes $206 million due after 2017 to a ComEd financing trust.

(b)

(c)	As of December 31, 2012, ComEd’s liability for uncertain tax positions was $67 million. 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)	On December 17, 2010, ComEd entered into 20-year contracts with several unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. See Note 3 of Combined Notes to Consolidated Financial Statements for additional information.

(e)

Under its operating agreement with PJM, ComEd is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd’s, expected portion of the costs to pay for the completion of the required construction projects. See Note 3 of Combined Notes to Consolidated Financial Statements for additional information.

PECO


			Payment due within
	Total		2013		2014- 2015		2016- 2017		Due 2018 and beyond		All Other
Long-term debt ^(a)		$2,134	$	300	$	250	$	—	$	1,584	$	—
Interest payments on long-term debt^(b)		1,238		105		168		158		807		—
Liability and interest for uncertain tax positions^(c)		1		1		—		—		—		—
Operating leases		42		20		16		6		—		—
Fuel purchase agreements ^(d)		444		145		158		64		77		—
Electric supply procurement ^(d)		799		561		238		—		—		—
AEC purchase commitments ^(d)		33		12		11		4		6		—
PJM regional transmission expansion commitments ^(e)		140		28		49		63		—		—

Total contractual obligations	$	4,831	$	1,172	$	890	$	295	$	2,474	$	—

(a)	Includes $184 million due after 2017 to PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2012 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(c)	As of December 31, 2012, 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.

159

(d)	Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information.

(e)

Under its operating agreement with PJM, PECO is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PECO’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 of Combined Notes to Consolidated Financial Statements for additional information.

BGE


			Payment due within
	Total		2013		2014- 2015		2016- 2017		Due 2018 and beyond		All Other
Long-term debt ^(a)		$2,440		$467		$145	$	420	$	1,408	$	—
Interest payments on long-term debt^(b)		1,644		118		212		176		1,138		—
Liability and interest for uncertain tax positions		—		—		—		—		—		—
Operating leases		73		12		19		13		29		—
Fuel purchase agreements ^(c)		654		133		127		104		290		—
Electric supply procurement ^(c)		1,401		859		542		—		—		—
Curtailment services commitments ^(c)		153		49		88		16		—		—
PJM regional transmission expansion commitments ^(d)		249		15		172		62		—		—

Total contractual obligations	$	6,614	$	1,653	$	1,305	$	791	$	2,865	$	—

(a)	Includes $258 million due after 2017 to the BGE financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2012 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(c)	Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services. See Note 19 of the Combined Notes to Consolidated Financial Statements for additional information.

(d)

Under its operating agreement with PJM, BGE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent BGE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 of Combined Notes to Consolidated Financial Statements for additional information.

See Note 19 of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ other commitments potentially triggered by future events.

For additional information regarding:

•

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

•

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

•

liabilities related to uncertain tax positions, see Note 12 of the Combined Notes to Consolidated Financial Statements.

•

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

•

operating leases, energy commitments, fuel purchase agreements, construction commitments and rate relief commitments, see Note 19 of the Combined Notes to Consolidated Financial Statements.

•

the nuclear decommissioning and SNF obligations, see Notes 13 and 19 of the Combined Notes to Consolidated Financial Statements.

•

regulatory commitments, see Note 3 of the Combined Notes to Consolidated Financial Statements.

160

•

variable interest entities, see Note 1 of the Combined Notes to Consolidated Financial Statements.

•

nuclear insurance, see Note 19 of the Combined Notes to Consolidated Financial Statements.

•

new accounting pronouncements, see Note 1 of the Combined Notes to Consolidated Financial Statements.

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 executive officer, chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Risk Oversight Committee of the Exelon Board of Directors on the scope of the risk management activities.

Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)

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. 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. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel, and other commodities.

Generation

Normal Operations and Hedging Activities. Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of ComEd’s, PECO’s and BGE’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, including the ComEd financial swap contract, will occur during 2013 through 2015. Generation’s energy contracts are accounted for under the accounting guidance for derivatives as further discussed in Note 10 of the Combined Notes to Consolidated Financial Statements.

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, 2012, the percentage of expected generation hedged for the major reportable segments was 94%-97%, 62%-65% and 27%-30% for 2013, 2014 and 2015, 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 economic hedges and certain non-derivative contracts including sales to ComEd, PECO and BGE to serve their retail load.

161

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. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire non-trading portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on December 31, 2012, market conditions and hedged position would be a decrease in pre-tax net income of approximately $40 million, $440 million and $810 million, respectively, for 2013, 2014 and 2015. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk 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 also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (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. The proprietary trading activities, which included physical volumes of 12,958 GWh, 5,742 GWh, and 3,625 GWh for the years ended December 31, 2012, 2011 and 2010 respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Trading portfolio activity for the year ended December 31, 2012, resulted in pre-tax losses of $14 million due to net mark-to-market gains of $96 million and realized losses of $110 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period, one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $1.9 million of exposure since the merger date and was deemed immaterial prior to the merger. 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, 2012 of $7,376 million, Generation has not segregated proprietary trading activity in the following tables.

Fuel Procurement. Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained primarily 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 60% of Generation’s uranium concentrate requirements from 2013 through 2017 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 19 of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.

162

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. This financial swap contract between Generation and ComEd expires on May 31, 2013.

ComEd’s 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. ComEd is permitted full recovery of its RFP contracts from retail customers with no mark-up.

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. Delivery under these contracts began in June 2012. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Notes 3 and 10 of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.

PECO

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 3 of the Combined Notes to the Consolidated Financial Statements. PECO’s full requirements contracts and block contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. Under the DSP Programs, PECO is permitted to recover its electric supply procurement costs from retail customers with no mark-up.

PECO has also entered into derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 of the Combined Notes to Consolidated Financial Statements.

BGE

BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. Under the SOS program, BGE is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for the residential shareholder return component of the administrative charge.

163

BGE has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.

BGE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 of the Combined Notes to Consolidated Financial Statements.

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).

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, 2011, to December 31, 2012. 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 cash flow hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets. This table excludes all normal purchase and normal sales contracts. For additional information on the cash flow hedge gains and losses included within accumulated OCI and the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2012, and December 31, 2011, refer to Note 10 of the Combined Notes to Consolidated Financial Statements.


	Generation			ComEd			PECO			Intercompany Eliminations ^(h)			Exelon
Total mark-to-market energy contract net assets (liabilities) at January 1, 2011 ^(a)	$	1,803		$	(971	)	$	(9	)	$	—		$	823
Total change in fair value during 2011 of contracts recorded in result of operations		241			—			—			—			241
Reclassification to realized at settlement of contracts recorded in results of operations		(541	)		—			—			—			(541	)
Ineffective portion recognized in income ^(b)		9			—			—			—			9
Reclassification to realized at settlement from accumulated OCI ^(c)		(968	)		—			—			456			(512	)
Effective portion of changes in fair value—recorded in OCI ^(d)		827			—			—			(170	)		657
Changes in fair value—energy derivatives		—			171	^(e)		9	^(f)		(286	)		(106	)
Changes in collateral		411			—			—			—			411
Changes in net option premium paid/(received)		3			—			—			—			3
Option Premium Amortization ^(g)		(137	)		—			—			—			(137	)

Total mark-to-market energy contract net assets (liabilities) at December 31, 2011 ^(a)	$	1,648		$	(800	)	$	—		$	—		$	848
Contracts Acquired at merger date ⁽ⁱ⁾		140												140
Total change in fair value during 2012 of contracts recorded in result of operations		(159	)		—			—			7			(152	)
Reclassification to realized at settlement of contracts recorded in results of operations		775			—			—			—			775
Ineffective portion recognized in income ^(b)		(5	)		—			—			—			(5	)

164


	Generation			ComEd			PECO		Intercompany Eliminations ^(h)			Exelon
Reclassification to realized at settlement from accumulated OCI ^(c)		(1,368	)		—			—		621			(747	)
Effective portion of changes in fair value—recorded in OCI ^(d)		719			—			—		(146	)		573
Changes in fair value—energy derivatives		—			507	^(e)		—		(482	)		25
Changes in collateral		(89	)		—			—		—			(89	)
Changes in net option premium paid/(received)		114			—			—		—			114
Option Premium Amortization ^(g)		(160	)		—			—		—			(160	)
Intercompany Elimination of Existing Derivative Contracts with Constellation		(103	)										(103	)
Other changes in fair value		(7	)		—			—		—			(7	)

Total mark-to-market energy contract net assets (liabilities) at December 31, 2012 ^(a)	$	1,505		$	(293	)	$	—	$	—		$	1,212

(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)	For Generation, reflects $5 million and $9 million of changes in cash flow hedge ineffectiveness, of which none was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO for the years ended December 31, 2012 and 2011, respectively.

(c)

For Generation, includes $621 million and $451 million of losses from reclassifications from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011, respectively, and $5 million of losses from reclassifications from accumulated OCI to recognize gains in net income related to settlements of the PECO block contracts for the year ended December 31, 2011.

(d)

For Generation, includes $146 million and $170 million of gains related to the changes in fair value of the five-year financial swap with ComEd for the years ended December 31, 2012 and 2011, respectively. Effective prior to the merger, the five-year financial swap between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation.

(e)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2012 and 2011, ComEd recorded a regulatory liability of $293 million and $800 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. During 2012 and 2011, this includes $98 million of increases and $170 million of decreases in fair value, respectively, and $566 million and $451 million of realized gains, respectively, due to settlements of ComEd’s five-year financial swap with Generation. During 2012 and 2011 this includes $34 million and $110 million, respectively, of increases in fair value, and during 2012 realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.

(f)

For PECO, the changes in fair value are recorded as a change in regulatory assets or liabilities. During the year ended December 31, 2011, PECO’s mark-to-market derivative liability was fully amortized, including $5 million related to PECO’s block contracts with Generation, in accordance with the terms of the contracts.

(g)	Includes $160 million and $137 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, 2012 and 2011, respectively.

(h)	Amounts related to the five-year financial swap between Generation and ComEd and the block contracts between Generation and PECO are eliminated in consolidation.

(i)	For Generation, includes $660 million of collateral paid to counterparties, offset by $520 million of unrealized losses on commodity derivative positions.

Fair Values

The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide 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 net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities) net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 9 of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

165

Exelon


	Maturities Within															Total Fair Value
	2013		2014			2015			2016		2017		2018 and Beyond			Total Fair Value
Normal Operations, Commodity derivative contracts ^(a)(b):
Actively quoted prices (Level 1)	$	80	$	(63	)	$	(32	)	$	10	$	2	$	—		$	(3	)
Prices provided by external sources (Level 2)		325		374			134			16		—		(1	)		848
methods (Level 3) ^(c)		168		89			50			30		25		5			367

Total	$	573	$	400		$	152		$	56	$	27	$	4		$	1,212

(a)	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.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $31 million at December 31, 2012.

(c)	Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Generation


	Maturities Within															Total Fair Value
	2013		2014			2015			2016		2017		2018 and Beyond			Total Fair Value
Normal Operations, Commodity derivative contracts ^(a)(b) :
Actively quoted prices (Level 1)	$	80	$	(63	)	$	(32	)	$	10	$	2	$	—		$	(3	)
Prices provided by external sources (Level 2)		325		374			134			16		—		(1	)		848
Prices based on model or other valuation methods (Level 3)		412		106			66			44		38		(6	)		660

Total	$	817	$	417		$	168		$	70	$	40	$	(7	)	$	1,505

(a)	Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts are recorded in results of operations. Amounts include a $226 million gain associated with the five-year financial swap with ComEd.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $31 million at December 31, 2012.

ComEd


	Maturities Within																	Fair Value
	2013			2014			2015			2016			2017			2018 and Beyond		Fair Value
Prices based on model or other valuation methods^(a)	$	(244	)	$	(17	)	$	(16	)	$	(14	)	$	(13	)	$	11	$	(293	)

(a)	Represents ComEd’s net assets (liabilities) associated with the five-year financial swap with Generation and the floating-to-fixed energy swap contracts with unaffiliated suppliers.

166

Credit Risk, Collateral, and Contingent Related Features (Exelon, Generation, ComEd, PECO and BGE)

Generation

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, 2012. 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 duration 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 exchanges (i.e. NYMEX, ICE, etc), which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and BGE of $54 million, $56 million and $31 million, respectively. See Note 22 of the Combined Notes to Consolidated Financial Statements for further information.


Rating as of December 31, 2012	Total Exposure Before Credit Collateral		Credit Collateral ^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure		Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,984	$	347	$	1,637		1	$	262
Non-investment grade		28		24		4		—		—
No external ratings
Internally rated—investment grade		512		10		502		1		271
Internally rated—non-investment grade		41		3		38		—		—

Total	$	2,565	$	384	$	2,181		2	$	533


	Maturity of Credit Risk Exposure
Rating as of December 31, 2012	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	1,553	$	319	$	112	$	1,984
Non-investment grade		15		13		—		28
No external ratings
Internally rated—investment grade		312		193		7		512
Internally rated—non-investment grade		41		—		—		41

Total	$	1,921	$	525	$	119	$	2,565

167


Net Credit Exposure by Type of Counterparty	As of December 31, 2012
Investor-owned utilities, marketers and power producers	$	865
Energy cooperatives and municipalities		786
Financial Institutions		422
Other		108

Total	$	2,181

(a)	As of December 31, 2012, credit collateral held from counterparties where Generation had credit exposure included $344 million of cash and $40 million of letters of credit.

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 is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. 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, 2012. See Note 3 of the Combined Notes to 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 forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. As of December 31, 2012, ComEd’s credit exposure to energy suppliers was immaterial.

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 to provide for the potential loss from nonpayment by these customers. See Note 1 of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. 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, 2012.

168

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 the major credit rating agencies 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, 2012, PECO had no net credit exposure with suppliers.

PECO does not obtain cash collateral from suppliers under its natural gas supply and asset management agreements; however, the natural gas asset managers have provided $20 million in parental guarantees related to these agreements. As of December 31, 2012, PECO had credit exposure of $7 million under its natural gas supply and asset management agreements with investment grade suppliers.

BGE

Credit risk for BGE is managed by credit and collection policies, which are consistent with state regulatory requirements. BGE is currently obligated to provide service to all electric customers within its franchised territory. BGE records a provision for uncollectible accounts to provide for the potential loss from nonpayment by these customers. BGE will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. See Note 1 of the Combined Notes to Consolidated Financial Statements for uncollectible accounts policy. MDPSC regulations prohibit BGE from terminating service to residential customers due to nonpayment from November 1 through March 31 if the forecasted temperature is 32 degrees or below for the subsequent 72 hour period. BGE is also prohibited by the Maryland Public Utilities Article and MDPSC regulations from terminating service to residential customers due to nonpayment if the forecasted temperature is 95 degrees or above for the subsequent 72 hour period. BGE did not have any customers representing over 10% of its revenues as of December 31, 2012.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, 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 the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. 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. The seller’s credit exposure is calculated each business day. As of December 31, 2012, BGE had no net credit exposure with suppliers.

BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At December 31, 2012, BGE had credit exposure of $8 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third party suppliers.

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Collateral (Exelon, Generation, ComEd, PECO and BGE)

Generation

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase 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, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. See Note 10 of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements.

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, Generation depends on access to bank credit facilities which serve as liquidity sources to fund collateral requirements. Generation depends on access to bank credit lines which serve as liquidity sources to fund collateral requirements. See Note 11 of the Combined Notes to Consolidated Financial Statements for additional information.

As of December 31, 2012, Generation had $499 million of cash collateral deposits received from counterparties and Generation had $527 million of cash collateral deposits being held by counterparties, of which $31 million in net cash collateral deposits were offset against mark-to-market assets and liabilities. As of December 31, 2012, $3 million of cash collateral received was not offset against net derivative positions because it was not associated with energy-related derivatives. As of December 31, 2011, Generation was holding $542 million of cash collateral deposits received from counterparties. Net cash collateral deposits received of $540 million were offset mark-to-market assets and liabilities. As of December 31, 2011, $2 million of cash collateral received was not offset against net mark-to-market assets and liabilities. See Note 19 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

ComEd

As of December 31, 2012, ComEd held immaterial amounts of cash and letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts and held approximately $19 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts. See Notes 3 and 10 of the Combined Notes to Consolidated Financial Statements for further information.

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PECO

As of December 31, 2012, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 10 of the Combined Notes to Consolidated Financial Statements for further information.

BGE

BGE is not required to post collateral under its electric supply contracts. As of December 31, 2012, BGE was not required to post collateral under its natural gas procurement contracts, nor was it holding collateral under its electric supply and natural gas procurement contracts. See Note 10 of the Combined Notes to Consolidated Financial Statements for further information.

RTOs and ISOs (Exelon, Generation, ComEd, PECO and BGE)

Generation, ComEd, PECO and BGE participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, ISO-NY, CISO, MISO, SPP, AESO, OIESO and 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 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 (Exelon and Generation)

Generation enters into commodity transactions on NYMEX, ICE and the Nodal exchange. The NYMEX, ICE and Nodal exchange clearinghouses act as the counterparty to each trade. Transactions on the NYMEX, ICE and Nodal exchange must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX, ICE and Nodal exchange are significantly collateralized and have limited counterparty credit risk.

Long-Term Leases (Exelon)

Exelon’s consolidated balance sheets, as of December 31, 2012, included a $693 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases. This investment represents the estimated residual value of leased assets at the end of the respective lease terms of approximately $1.5 billion, less unearned income of $799 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms which are set at prices above the then expected fair market value of the plants. If the lessees do not exercise the fixed purchase options the lessees return the leasehold interests to Exelon and Exelon has the ability to require the lessees to arrange a service contract with a third party for a period following the lease term. In any event, Exelon is subject to residual value risk to the extent the fair value of the assets are less than the residual value. This risk is mitigated by the fair value of the fixed payments under the service contract. The term of the service contract, however, is less than the expected remaining useful life of the plants and, therefore, Exelon’s exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. 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 creditworthiness of Exelon’s counterparties to these long-term leases. Since 2008, the entity providing the credit enhancement for one of the lessees did not meet the

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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. Exelon monitors the continuing credit quality of the credit enhancement party.

Exelon performed annual assessments as of July 31, 2012 and 2011 of the estimated fair value of long-term lease investments and concluded that the estimated fair values at the end of the lease terms exceeded the residual values ($1.5 billion as noted above) established at the lease dates and recorded as investments on Exelon’s balance sheet. Through December 31, 2012, no events have occurred or circumstances have changed that would require any formal reassessment subsequent to the July 2012 review.

Interest-Rate Risk (Exelon, Generation, ComEd, PECO and BGE)

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 rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2012, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and $452 million of notional amounts of pre-issuance hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper and PECO Accounts Receivables Facility) and fixed-to-floating swaps would result in less than $2 million decrease in Exelon pre-tax income for the year ended December 31, 2012.

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, 2012, 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 $386 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 7, 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 OPERATIONS

Generation

General

Generation operates in six segments: Mid-Atlantic, Midwest, New England, New York, ERCOT, and other regions in Generation. The operation of all six segments consists of owned contracted and investments in electric generating facilities, and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and investments in natural gas exploration and production activities. These segments are discussed in further detail in “ITEM 1. BUSINESS—Generation” of this Form 10-K.

Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under “ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Exelon—Executive Overview” of this Form 10-K.

Results of Operations

Year Ended December 31, 2012 Compared To Year Ended December 31, 2011 and Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

A discussion of Generation’s results of operations for 2012 compared to 2011 and 2011 compared to 2010 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 credit facilities in the aggregate of $5.6 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 11 of the Combined Notes to Consolidated 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 OPERATIONS

ComEd

General

ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussed in further detail in “ITEM 1. BUSINESS—ComEd” of this Form 10-K.

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, 2012 Compared to Year Ended December 31, 2011 and Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

A discussion of ComEd’s results of operations for 2012 compared to 2011 and for 2011 compared to 2010 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, commercial paper 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, 2012, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion. See the “Credit Matters” section of “Liquidity and Capital Resources” for additional discussion.

See the “EXELON CORPORATION—Liquidity and Capital Resources” and Note 11 of the Combined Notes to Consolidated 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 OPERATIONS

PECO

General

PECO operates in a single business 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. This segment is discussed in further detail in “ITEM 1. BUSINESS—PECO” of this Form 10-K.

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, 2012 Compared to Year Ended December 31, 2011 and Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

A discussion of PECO’s results of operations for 2012 compared to 2011 and for 2011 compared to 2010 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, 2012, PECO had access to a revolving credit facility with aggregate bank commitments of $600 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 7.

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

BGE

General

BGE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution service in central Maryland, including the City of Baltimore. This segment is discussed in further detail in “ITEM 1. BUSINESS—BGE” of this Form 10-K.

Executive Overview

A discussion of items pertinent to BGE’s executive overview is set forth under “EXELON CORPORATION—Executive Overview” of this Form 10-K.

Results of Operations

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 and Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

A discussion of BGE’s results of operations for 2012 compared to 2011 and for 2011 compared to 2010 is set forth under “Results of Operations—BGE” in “EXELON CORPORATION—Results of Operations” of this Form 10-K.

Liquidity and Capital Resources

BGE’s business is capital intensive and requires considerable capital resources. BGE’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 commercial paper. BGE’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 BGE no longer has access to the capital markets at reasonable terms, BGE has access to a revolving credit facility. At December 31, 2012, BGE had access to a revolving credit facility with aggregate bank commitments of $600 million. See the “Credit Matters” section of “Liquidity and Capital Resources” for additional discussion.

Capital resources are used primarily to fund BGE’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans. Additionally, BGE 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 BGE’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 BGE’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 BGE’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 BGE 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 BGE’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, PECO and BGE—Critical Accounting Policies and Estimates above for a discussion of BGE’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

BGE

BGE 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, as such term is defined in Exchange Act Rule 13a-15(f). 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.

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, 2012. 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, 2012, Exelon’s internal control over financial reporting was effective.

The effectiveness of the Exelon’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 21, 2013

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Management’s Report on Internal Control Over Financial Reporting

The management of Exelon Generation Company, LLC (Generation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). 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.

Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2012. 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, 2012, Generation’s internal control over financial reporting was effective.

The effectiveness of the Generation’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 21, 2013

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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, as such term is defined in Exchange Act Rule 13a-15(f). 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.

ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, 2012. 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, 2012, ComEd’s internal control over financial reporting was effective.

The effectiveness of the ComEd’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 21, 2013

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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, as such term is defined in Exchange Act Rule 13a-15(f). 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.

PECO’s management conducted an assessment of the effectiveness of PECO’s internal control over financial reporting as of December 31, 2012. 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, 2012, PECO’s internal control over financial reporting was effective.

The effectiveness of the PECO’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 21, 2013

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Management’s Report on Internal Control Over Financial Reporting

The management of Baltimore Gas and Electric Company (BGE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). 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.

BGE’s management conducted an assessment of the effectiveness of BGE’s internal control over financial reporting as of December 31, 2012. 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, BGE’s management concluded that, as of December 31, 2012, BGE’s internal control over financial reporting was effective.

The effectiveness of BGE’s internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 21, 2013

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Exelon Corporation:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Exelon Corporation and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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 index appearing under item 15(a)(2) 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, 2012, 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 the accompanying 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.

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.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 21, 2013

186

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Member of Exelon Generation Company, LLC:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Exelon Generation Company, LLC and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under item 15(a)(2) 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, 2012, 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 the accompanying 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.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 21, 2013

187

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Commonwealth Edison Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Commonwealth Edison Company and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under item 15(a)(2) 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, 2012, 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 the accompanying 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.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 21, 2013

188

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of PECO Energy Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of PECO Energy Company and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under item 15(a)(2) 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, 2012, 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 the accompanying 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.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 21, 2013

189

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Baltimore Gas and Electric Company

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Baltimore Gas and Electric Company and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under item 15(a)(2) 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, 2012, 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 the accompanying 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 audits (which was an integrated audit in 2012). 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.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 21, 2013

190

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions, except per share data)	2012			2011			2010
Operating revenues	$	23,489		$	19,063		$	18,644
Operating expenses
Purchased power and fuel		10,157			7,267			6,435
Operating and maintenance		7,961			5,184			4,600
Depreciation and amortization		1,881			1,347			2,075
Taxes other than income		1,019			785			808

Total operating expenses		21,018			14,583			13,918

Equity in losses of unconsolidated affiliates		(91	)		(1	)		—
Operating income		2,380			4,479			4,726

Other income and (deductions)
Interest expense, net		(903	)		(701	)		(792	)
Interest expense to affiliates, net		(25	)		(25	)		(25	)
Other, net		346			203			312

Total other income and (deductions)		(582	)		(523	)		(505	)

Income before income taxes		1,798			3,956			4,221
Income taxes		627			1,457			1,658

Net income		1,171			2,499			2,563
Net Income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		11			4			—

Net income on common stock		1,160			2,495			2,563

Other comprehensive loss
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs, net of taxes of $1, $(4) and $(7). respectively		1			(5	)		(11	)
Actuarial loss reclassified to periodic cost, net of taxes of $110, $93 and $79, respectively		168			136			114
Transition obligation reclassified to periodic cost, net of taxes of $2, $2 and $2, respectively		2			4			3
Pension and non-pension postretirement benefit plan valuation adjustment, net of taxes of $(237), $(171) and $(188), respectively		(371	)		(250	)		(288	)
Change in unrealized gain (loss) on cash flow hedges, net of taxes of $(68), $39 and $(107), respectively		(120	)		88			(151	)
Change in unrealized gain (loss) on marketable securities, net of taxes of $(1), $0 and $0, respectively		2			—			(1	)
Change in unrealized gain (loss) on equity investments, net of taxes of $1, $0 and $0, respectively		1			—			—

Other comprehensive loss		(317	)		(27	)		(334	)

Comprehensive income	$	854		$	2,472		$	2,229

Average shares of common stock outstanding:
Basic		816			663			661
Diluted		819			665			663
Earnings per average common share:
Basic	$	1.42		$	3.76		$	3.88
Diluted	$	1.42		$	3.75		$	3.87

Dividends per common share	$	2.10		$	2.10		$	2.10

See the Combined Notes to Consolidated Financial Statements

191

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Cash flows from operating activities
Net income	$	1,171		$	2,499		$	2,563
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		4,079			2,316			2,943
Loss on sale of three Maryland generating stations		272			—			—
Deferred income taxes and amortization of investment tax credits		615			1,457			981
Net fair value changes related to derivatives		(604	)		291			(88	)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		(157	)		14			(105	)
Other non-cash operating activities		1,383			770			609
Changes in assets and liabilities:
Accounts receivable		243			57			(232	)
Inventories		26			(58	)		(62	)
Accounts payable, accrued expenses and other current liabilities		(632	)		(254	)		472
Option premiums paid, net		(114	)		(3	)		(124	)
Counterparty collateral received (posted), net		135			(344	)		(155	)
Income taxes		544			492			(543	)
Pension and non-pension postretirement benefit contributions		(462	)		(2,360	)		(959	)
Other assets and liabilities		(368	)		(24	)		(56	)

Net cash flows provided by operating activities		6,131			4,853			5,244

Cash flows from investing activities
Capital expenditures		(5,789	)		(4,042	)		(3,326	)
Proceeds from nuclear decommissioning trust fund sales		7,265			6,139			3,764
Investment in nuclear decommissioning trust funds		(7,483	)		(6,332	)		(3,907	)
Cash and restricted cash acquired from Constellation		964			—			—
Acquisitions of long lived assets		(21	)		(387	)		(893	)
Proceeds from sale of three Maryland generating stations		371			—			—
Proceeds from sales of investments		28			6			28
Purchases of investments		(13	)		(4	)		(22	)
Change in restricted cash		(34	)		(3	)		423
Other investing activities		136			20			39

Net cash flows used in investing activities		(4,576	)		(4,603	)		(3,894	)

Cash flows from financing activities
Payment of accounts receivable agreement		(15	)		—			—
Changes in short-term debt		(197	)		161			(155	)
Issuance of long-term debt		2,027			1,199			1,398
Retirement of long-term debt		(1,145	)		(789	)		(828	)
Retirement of long-term debt of variable interest entity		—			—			(806	)
Dividends paid on common stock		(1,716	)		(1,393	)		(1,389	)
Proceeds from employee stock plans		72			38			48
Other financing activities		(111	)		(62	)		(16	)

Net cash flows used in financing activities		(1,085	)		(846	)		(1,748	)

Increase (decrease) in cash and cash equivalents		470			(596	)		(398	)
Cash and cash equivalents at beginning of period		1,016			1,612			2,010

Cash and cash equivalents at end of period	$	1,486		$	1,016		$	1,612

See the Combined Notes to Consolidated Financial Statements

192

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	1,411	$	1,016
Cash and cash equivalents of variable interest entities		75		—
Restricted cash and investments		86		40
Restricted cash and investments of variable interest entities		47		—
Accounts receivable, net
Customer ($289 and $346 gross accounts receivables pledged as collateral as of December 31, 2012 and December 31, 2011, respectively)		2,787		1,613
Other		1,147		1,000
Accounts receivable, net, of variable interest entities		292		—
Mark-to-market derivative assets		938		432
Unamortized energy contract assets		886		16
Inventories, net
Fossil fuel		246		208
Materials and supplies		768		656
Deferred income taxes		131		—
Regulatory assets		759		390
Other		560		342

Total current assets		10,133		5,713

Property, plant and equipment, net		45,186		32,570
Deferred debits and other assets
Regulatory assets		6,497		4,518
Nuclear decommissioning trust funds		7,248		6,507
Investments		1,184		751
Investments in affiliates		22		15
Investment in CENG		1,849		—
Goodwill		2,625		2,625
Mark-to-market derivative assets		937		650
Unamortized energy contract assets		1,073		424
Pledged assets for Zion Station decommissioning		614		734
Deferred income taxes		58		—
Other		1,128		488

Total deferred debits and other assets		23,235		16,712

Total assets	$	78,554	$	54,995

See the Combined Notes to Consolidated Financial Statements

193

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012			2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—		$	163
Short-term notes payable—accounts receivable agreement		210			225
Long-term debt due within one year		975			828
Long-term debt due within one year of variable interest entities		72			—
Accounts payable		2,446			1,444
Accounts payable of variable interest entities		202			—
Mark-to-market derivative liabilities		352			112
Unamortized energy contract liabilities		455			—
Accrued expenses		1,800			1,255
Deferred income taxes		58			1
Regulatory liabilities		321			197
Dividends payable		4			349
Other		889			560

Total current liabilities		7,784			5,134

Long-term debt		17,190			11,799
Long-term debt to financing trusts		648			390
Long-term debt of variable interest entities		508			—
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		11,551			8,253
Asset retirement obligations		5,074			3,884
Pension obligations		3,428			2,194
Non-pension postretirement benefit obligations		2,662			2,263
Spent nuclear fuel obligation		1,020			1,019
Regulatory liabilities		3,981			3,627
Mark-to-market derivative liabilities		281			126
Unamortized energy contract liabilities		528			—
Payable for Zion Station decommissioning		432			563
Other		1,650			1,268

Total deferred credits and other liabilities		30,607			23,197

Total liabilities		56,737			40,520

Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 855 and 663 shares outstanding at December 31, 2012 and 2011, respectively)		16,632			9,107
Treasury stock, at cost (35 shares held at December 31, 2012 and 2011, respectively)		(2,327	)		(2,327	)
Retained earnings		9,893			10,055
Accumulated other comprehensive loss, net		(2,767	)		(2,450	)

Total shareholders’ equity		21,431			14,385
BGE preference stock not subject to mandatory redemption		193			—
Noncontrolling interest		106			3

Total equity		21,730			14,388

Total liabilities and shareholders’ equity	$	78,554		$	54,995

See the Combined Notes to Consolidated Financial Statements

194

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			Noncontrolling Interest			Preferred and Preference Stock			Total Shareholders’ Equity
Balance, December 31, 2009		694,565	$	8,923	$	(2,328	)	$	8,134		$	(2,089	)	$	—			—		$	12,640
Net income		—		—		—			2,563			—			—			—			2,563
Long-term incentive plan activity		1,380		60		1			(1	)		—			—			—			60
Employee stock purchase plan issuances		644		23		—			—			—			—			—			23
Common stock dividends		—		—		—			(1,392	)		—			—			—			(1,392	)
Acquisition of Exelon Wind		—		—		—			—			—			3			—			3
Other comprehensive income, net of income taxes of $(221)		—		—		—			—			(334	)		—			—			(334	)

Balance, December 31, 2010		696,589	$	9,006	$	(2,327	)	$	9,304		$	(2,423	)	$	3		$	—		$	13,563
Net income		—		—		—			2,495			—			—			4			2,499
Long-term incentive plan activity		861		76		—			—			—			—			—			76
Employee stock purchase plan issuances		662		25		—			—			—			—			—			25
Common stock dividends		—		—		—			(1,744	)		—			—			—			(1,744	)
Preferred and preference stock dividends		—		—		—			—			—			—			(4	)		(4	)
Other comprehensive loss, net of income taxes of $(41)		—		—		—			—			(27	)		—			—			(27	)

Balance, December 31, 2011		698,112	$	9,107	$	(2,327	)	$	10,055		$	(2,450	)	$	3			—		$	14,388
Net income		—		—		—			1,160			—			(3	)		14			1,171
Long-term incentive plan activity		2,432		126		—			—			—			—			—			126
Employee stock purchase plan issuances		857		26		—			—			—			—			—			26
Common stock dividends		—		—		—			(1,322	)		—			—			—			(1,322	)
Common stock issuance Constellation merger		188,124		7,365		—			—			—			—			—			7,365
Noncontrolling interest acquired		—		8		—			—			—			106			—			114
BGE preference stock acquired		—		—		—			—			—			—			193			193
Preferred and preference stock dividends		—		—		—			—			—			—			(14	)		(14	)
Other comprehensive loss, net of income taxes of $(192)		—		—		—			—			(317	)		—			—			(317	)

Balance, December 31, 2012		889,525	$	16,632	$	(2,327	)	$	9,893		$	(2,767	)	$	106			193		$	21,730

See the Combined Notes to Consolidated Financial Statements

195

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Operating revenues
Operating revenues	$	12,735		$	9,286		$	6,923
Operating revenues from affiliates		1,702			1,161			3,102

Total operating revenues		14,437			10,447			10,025

Operating expenses
Purchased power and fuel		7,061			3,589			3,463
Operating and maintenance		4,398			2,827			2,521
Operating and maintenance from affiliates		630			321			291
Depreciation and amortization		768			570			474
Taxes other than income		369			264			230

Total operating expenses		13,226			7,571			6,979

Equity in losses of unconsolidated affiliates		(91	)		(1	)		—
Operating income		1,120			2,875			3,046

Other income and (deductions)
Interest expense		(301	)		(170	)		(153	)
Other, net		239			122			257

Total other income and (deductions)		(62	)		(48	)		104

Income before income taxes		1,058			2,827			3,150
Income taxes		500			1,056			1,178

Net income		558			1,771			1,972
Net loss attributable to noncontrolling interests		(4	)		—			—

Net income on membership interest		562			1,771			1,972
Other comprehensive income (loss)
Change in unrealized loss on cash flow hedges, net of income taxes of $(262), $(64) and $(102), respectively		(403	)		(98	)		(144	)
Change in unrealized income on equity investments, net of income taxes of $(1), $0 and $0, respectively		1			—			—

Other comprehensive loss		(402	)		(98	)		(144	)

Comprehensive income	$	156		$	1,673		$	1,828

See the Combined Notes to Consolidated Financial Statements

196

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Cash flows from operating activities
Net income	$	558		$	1,771		$	1,972
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		2,966			1,539			1,341
Loss on sale of three Maryland generating stations		272			—			—
Deferred income taxes and amortization of investment tax credits		408			551			741
Net fair value changes related to derivatives		(611	)		291			(88	)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		(157	)		14			(105	)
Other non-cash operating activities		537			421			182
Changes in assets and liabilities:
Accounts receivable		248			(122	)		—
Receivables from and payables to affiliates, net		39			208			(5	)
Inventories		31			(47	)		(70	)
Accounts payable, accrued expenses and other current liabilities		(499	)		34			(18	)
Option premiums paid, net		(114	)		(3	)		(124	)
Counterparty collateral (posted) received, net		95			(410	)		(1	)
Income taxes		114			193			(303	)
Pension and non-pension postretirement benefit contributions		(178	)		(1,070	)		(445	)
Other assets and liabilities		(128	)		(57	)		(45	)

Net cash flows provided by operating activities		3,581			3,313			3,032

Cash flows from investing activities
Capital expenditures		(3,554	)		(2,491	)		(1,883	)
Proceeds from nuclear decommissioning trust fund sales		7,265			6,139			3,764
Investment in nuclear decommissioning trust funds		(7,483	)		(6,332	)		(3,907	)
Cash and restricted cash acquired from Constellation		708			—			—
Proceeds from sale of three Maryland generating stations		371			—			—
Acquisitions of long lived assets		(21	)		(387	)		(893	)
Change in restricted cash		4			—			4
Other investing activities		81			(6	)		19

Net cash flows used in investing activities		(2,629	)		(3,077	)		(2,896	)

Cash flows from financing activities
Change in short-term debt		(52	)		—			—
Issuance of long-term debt		1,076			—			898
Retirement of long-term debt		(145	)		(2	)		(215	)
Distribution to member		(1,626	)		(172	)		(1,508	)
Contribution from member		48			30			62
Other financing activities		(78	)		(52	)		(16	)

Net cash flows used in financing activities		(777	)		(196	)		(779	)

Increase (decrease) in cash and cash equivalents		175			40			(643	)
Cash and cash equivalents at beginning of period		496			456			1,099

Cash and cash equivalents at end of period	$	671		$	496		$	456

See the Combined Notes to Consolidated Financial Statements

197

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	596	$	496
Cash and cash equivalents of variable interest entities		75		—
Restricted cash and cash equivalents		—		5
Restricted cash and cash equivalents of variable interest entities		16		—
Accounts receivable, net
Customer		1,482		578
Other		472		257
Accounts receivable, net, of variable interest entities		292		—
Mark-to-market derivative assets		938		432
Mark-to-market derivative assets with affiliate		226		503
Receivables from affiliates		141		109
Unamortized energy contract assets		886		16
Inventories, net
Fossil fuel		130		120
Materials and supplies		626		556
Other		331		145

Total current assets		6,211		3,217

Property, plant and equipment, net		19,531		13,475
Deferred debits and other assets
Nuclear decommissioning trust funds		7,248		6,507
Investments		420		42
Investment in CENG		1,849		—
Mark-to-market derivative assets		924		635
Mark-to-market derivative assets with affiliate		—		191
Prepaid pension asset		1,975		2,068
Pledged assets for Zion Station decommissioning		614		734
Unamortized energy contract assets		1,073		424
Other		836		140

Total deferred debits and other assets		14,939		10,741

Total assets	$	40,681	$	27,433

See the Combined Notes to Consolidated Financial Statements

198

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012		2011
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	—	$	2
Long-term debt due within one year		24		3
Long-term debt due within one year of variable interest entities		4		—
Accounts payable		1,346		753
Accounts payable of variable interest entities		202		—
Accrued expenses		1,116		779
Payables to affiliates		193		58
Deferred income taxes		128		244
Mark-to-market derivative liabilities		334		103
Unamortized energy contract liabilities		378		—
Other		372		202

Total current liabilities		4,097		2,144

Long-term debt		5,245		3,674
Long-term debt to affiliate		2,007		—
Long-term debt of variable interest entities		203		—
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,398		3,966
Asset retirement obligations		4,938		3,767
Non-pension postretirement benefit obligations		755		703
Spent nuclear fuel obligation		1,020		1,019
Payables to affiliates		2,397		2,222
Mark-to-market derivative liabilities		232		29
Unamortized energy contract liabilities		516		—
Payable for Zion Station decommissioning		432		563
Other		776		638

Total deferred credits and other liabilities		16,464		12,907

Total liabilities		28,016		18,725

Commitments and contingencies
Equity
Member’s equity
Membership interest		8,876		3,556
Undistributed earnings		3,168		4,232
Accumulated other comprehensive income, net		513		915

Total member’s equity		12,557		8,703
Noncontrolling interest		108		5

Total equity		12,665		8,708

Total liabilities and equity	$	40,681	$	27,433

See the Combined Notes to Consolidated Financial Statements

199

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Changes in Member’s Equity


(In millions)	Member’s Equity								Noncontrolling Interest			Total Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interest			Total Equity
Balance, December 31, 2009	$	3,464	$	2,169		$	1,157		$	2		$	6,792
Net Income		—		1,972			—			—			1,972
Distribution to member		—		(1,508	)		—			—			(1,508	)
Allocation of tax benefit from member		62		—			—			—			62
Acquisition of Exelon Wind		—		—			—			3			3
Other comprehensive income, net of income taxes of $(102)		—		—			(144	)		—			(144	)

Balance, December 31, 2010	$	3,526	$	2,633		$	1,013		$	5		$	7,177
Net Income		—		1,771			—			—			1,771
Distribution to member		—		(172	)		—			—			(172	)
Allocation of tax benefit from member		30		—			—			—			30
Other comprehensive loss, net of income taxes of $(64)		—		—			(98	)		—			(98	)

Balance, December 31, 2011	$	3,556	$	4,232		$	915		$	5		$	8,708
Net income		—		562			—			(4	)		558
Distribution to member		—		(1,626	)		—			—			(1,626	)
Allocation of tax benefit from member		48		—			—			—			48
Acquisition of Constellation		5,264		—			—			—			5,264
Noncontrolling interest acquired		8		—			—			107			115
Other comprehensive loss, net of income taxes of $(261)		—		—			(402	)		—			(402	)

Balance, December 31, 2012	$	8,876	$	3,168		$	513		$	108		$	12,665

See the Combined Notes to Consolidated Financial Statements

200

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(in millions)	2012			2011			2010
Operating revenues
Operating revenues	$	5,441		$	6,054		$	6,202
Operating revenues from affiliates		2			2			2

Total operating revenues		5,443			6,056			6,204

Operating expenses
Purchased power		1,518			2,382			2,297
Purchased power from affiliate		789			653			1,010
Operating and maintenance		1,182			1,031			917
Operating and maintenance from affiliate		163			158			152
Depreciation and amortization		610			554			516
Taxes other than income		295			296			256

Total operating expenses		4,557			5,074			5,148

Operating income		886			982			1,056

Other income and (deductions)
Interest expense		(294	)		(330	)		(373	)
Interest expense to affiliates, net		(13	)		(15	)		(13	)
Other, net		39			29			24

Total other income and (deductions)		(268	)		(316	)		(362	)

Income before income taxes		618			666			694
Income taxes		239			250			357

Net income		379			416			337

Other comprehensive income
Change in unrealized gain (loss) on marketable securities, net of income taxes of $0, $0 and $0, respectively		1			—			(1	)

Other comprehensive income (loss)		1			—			(1	)

Comprehensive income	$	380		$	416		$	336

See the Combined Notes to Consolidated Financial Statements

201

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended
(In millions)	2012			2011			2010
Cash flows from operating activities
Net income	$	379		$	416		$	337
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		610			554			517
Deferred income taxes and amortization of investment tax credits		270			700			582
Other non-cash operating activities		252			184			238
Changes in assets and liabilities:
Accounts receivable		24			5			(46	)
Receivables from and payables to affiliates, net		(18	)		(287	)		(55	)
Inventories		(11	)		(9	)		(1	)
Accounts payable, accrued expenses and other current liabilities		59			(84	)		342
Counterparty collateral received (posted), net		40			66			(154	)
Income taxes		9			223			(233	)
Pension and non-pension postretirement benefit contributions		(138	)		(977	)		(317	)
Other assets and liabilities		(142	)		45			(133	)

Net cash flows provided by operating activities		1,334			836			1,077

Cash flows from investing activities
Capital expenditures		(1,246	)		(1,028	)		(962	)
Proceeds from sales of investments		28			6			28
Purchases of investments		(13	)		(4	)		(22	)
Other investing activities		19			19			17

Net cash flows used in investing activities		(1,212	)		(1,007	)		(939	)

Cash flows from financing activities
Changes in short-term debt		—			—			(155	)
Issuance of long-term debt		350			1,199			500
Retirement of long-term debt		(450	)		(537	)		(213	)
Contributions from parent		—			—			2
Dividends paid on common stock		(105	)		(300	)		(310	)
Other financing activities		(7	)		(7	)		(3	)

Net cash flows provided by (used in) financing activities		(212	)		355			(179	)

Increase (decrease) in cash and cash equivalents		(90	)		184			(41	)
Cash and cash equivalents at beginning of period		234			50			91

Cash and cash equivalents at end of period	$	144		$	234		$	50

See the Combined Notes to Consolidated Financial Statements

202

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	144	$	234
Restricted cash		—		3
Accounts receivable, net
Customer		539		655
Other		452		385
Inventories, net		91		81
Deferred income taxes		83		61
Counterparty collateral deposited		53		90
Regulatory assets		388		657
Other		25		22

Total current assets		1,775		2,188

Property, plant and equipment, net		13,826		13,121
Deferred debits and other assets
Regulatory assets		666		699
Investments		8		21
Investments in affiliates		6		6
Goodwill		2,625		2,625
Receivable from affiliates		2,039		1,860
Prepaid pension asset		1,661		1,803
Other		299		315

Total deferred debits and other assets		7,304		7,329

Total assets	$	22,905	$	22,638

See the Combined Notes to Consolidated Financial Statements

203

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012		2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	252	$	450
Accounts payable		379		325
Accrued expenses		295		318
Payables to affiliates		97		111
Customer deposits		136		136
Regulatory liabilities		130		137
Mark-to-market derivative liability		18		9
Mark-to-market derivative liability with affiliate		226		503
Other		122		82

Total current liabilities		1,655		2,071

Long-term debt		5,315		5,215
Long-term debt to financing trust		206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		4,272		3,993
Asset retirement obligations		99		89
Non-pension postretirement benefits obligations		273		271
Regulatory liabilities		3,229		3,042
Mark-to-market derivative liability		49		97
Mark-to-market derivative liability with affiliate		—		191
Other		484		426

Total deferred credits and other liabilities		8,406		8,109

Total liabilities		15,582		15,601

Commitments and contingencies
Shareholders’ equity
Common stock		1,588		1,588
Other paid-in capital		5,014		5,003
Retained earnings		721		447
Accumulated other comprehensive loss, net		—		(1	)

Total shareholders’ equity		7,323		7,037

Total liabilities and shareholders’ equity	$	22,905	$	22,638

See the Combined Notes to Consolidated Financial Statements

204

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity


(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance, December 31, 2009	$	1,588	$	4,990	$	(1,639	)	$	1,943		$	—		$	6,882
Net income		—		—		337			—			—			337
Common stock dividends		—		—		—			(310	)		—			(310	)
Allocation of tax benefit from parent		—		2		—			—			—			2
Appropriation of retained earnings for future dividends		—		—		(337	)		337			—			—
Other comprehensive income, net of income taxes of $0		—		—		—			—			(1	)		(1	)

Balance, December 31, 2010	$	1,588	$	4,992	$	(1,639	)	$	1,970		$	(1	)	$	6,910
Net income		—		—		416			—			—			416
Common stock dividends		—		—		—			(300	)		—			(300	)
Allocation of tax benefit from parent		—		11		—			—			—			11
Appropriation of retained earnings for future dividends		—		—		(416	)		416			—			—
Other comprehensive loss,

Balance, December 31, 2011	$	1,588	$	5,003	$	(1,639	)	$	2,086		$	(1	)	$	7,037
Net income		—		—		379			—			—			379
Common stock dividends		—		—		—			(105	)		—			(105	)
Allocation of tax benefit from parent		—		11		—			—			—			11
Appropriation of retained earnings for future dividends		—		—		(379	)		379			—			—
Other comprehensive income net of income taxes of $0		—		—		—			—			1			1

Balance, December 31, 2012	$	1,588	$	5,014	$	(1,639	)	$	2,360		$	—		$	7,323

See the Combined Notes to Consolidated Financial Statements

205

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Operating revenues
Operating revenues	$	3,183		$	3,715		$	5,514
Operating revenues from affiliates		3			5			5

Total operating revenues		3,186			3,720			5,519

Operating expenses
Purchased power and fuel		842			1,369			677
Purchased power from affiliate		533			495			2,085
Operating and maintenance		698			698			644
Operating and maintenance from affiliates		111			96			89
Depreciation and amortization		217			202			1,060
Taxes other than income		162			205			303

Total operating expenses		2,563			3,065			4,858

Operating income		623			655			661

Other income and (deductions)
Interest expense		(111	)		(122	)		(181	)
Interest expense to affiliates, net		(12	)		(12	)		(12	)
Other, net		8			14			8

Total other income and (deductions)		(115	)		(120	)		(185	)

Income before income taxes		508			535			476
Income taxes		127			146			152

Net income		381			389			324
Preferred security dividends		4			4			4

Net income on common stock		377			385			320

Comprehensive income, net of income taxes
Net income		381			389			324
Other comprehensive income (loss)
Amortization of realized gain on settled cash flow swaps, net of income taxes of $0, $0 and $(1), respectively		—			—			(1	)
Change in unrealized gain on marketable securities, net of income taxes of $0, $0 and $0, respectively		1			—			—

Other comprehensive income (loss)		1			—			(1	)

Comprehensive income	$	382		$	389		$	323

See the Combined Notes to Consolidated Financial Statements

206

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Cash flows from operating activities
Net income	$	381		$	389		$	324
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		217			202			1,060
Deferred income taxes and amortization of investment tax credits		37			253			(400	)
Other non-cash operating activities		125			100			108
Changes in assets and liabilities:
Accounts receivable		(14	)		225			(212	)
Receivables from and payables to affiliates, net		13			(217	)		86
Inventories		21			—			9
Accounts payable, accrued expenses and other current liabilities		(47	)		34			85
Income taxes		174			(45	)		118
Pension and non-pension postretirement benefit contributions		(45	)		(137	)		(106	)
Other assets and liabilities		16			14			78

Net cash flows provided by operating activities		878			818			1,150

Cash flows from investing activities
Capital expenditures		(422	)		(481	)		(545	)
Changes in intercompany money pool contributions		82			(82	)		—
Change in restricted cash		2			(2	)		414
Other investing activities		10			8			11

Net cash flows used in investing activities		(328	)		(557	)		(120	)

Cash flows from financing activities
Payment of accounts receivable agreement		(15	)		—			—
Issuance of long-term debt		350			—			—
Retirement of long-term debt		(375	)		(250	)		—
Retirement of long-term debt of variable interest entity		—			—			(806	)
Contributions from parent		9			18			43
Dividends paid on common stock		(343	)		(348	)		(224	)
Dividends paid on preferred securities		(4	)		(4	)		(4	)
Repayment of receivable from parent		—			—			180
Other financing activities		(4	)		(5	)		—

Net cash flows used in financing activities		(382	)		(589	)		(811	)

Increase (decrease) in cash and cash equivalents		168			(328	)		219
Cash and cash equivalents at beginning of period		194			522			303

Cash and cash equivalents at end of period	$	362		$	194		$	522

See the Combined Notes to Consolidated Financial Statements

207

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	362	$	194
Restricted cash and cash equivalents		—		2
Accounts receivable, net ($289 and $329 gross accounts receivable pledged as collateral as of December 31, 2012 and 2011, respectively)
Customer		364		380
Other		161		376
Inventories, net
Fossil fuel		65		87
Materials and supplies		19		18
Deferred income taxes		40		25
Receivable from Exelon intercompany money pool		—		82
Prepaid utility taxes		21		1
Regulatory assets		32		39
Other		30		39

Total current assets		1,094		1,243

Property, plant and equipment, net		6,078		5,874
Deferred debits and other assets
Regulatory assets		1,378		1,216
Investments		22		22
Investments in affiliates		8		8
Receivable from affiliates		360		365
Prepaid pension asset		373		382
Other		40		46

Total deferred debits and other assets		2,181		2,039

Total assets	$	9,353	$	9,156

See the Combined Notes to Consolidated Financial Statements

208

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2012		2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term notes payable—accounts receivable agreement	$	210	$	225
Long-term debt due within one year		300		375
Accounts payable		244		262
Accrued expenses		82		83
Payables to affiliates		76		62
Customer deposits		51		53
Regulatory liabilities		169		60
Other		26		25

Total current liabilities		1,158		1,145

Long-term debt		1,647		1,597
Long-term debt to financing trusts		184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,331		2,170
Asset retirement obligations		29		28
Non-pension postretirement benefits obligations		284		288
Regulatory liabilities		538		585
Other		113		134

Total deferred credits and other liabilities		3,295		3,205

Total liabilities		6,284		6,131

Commitments and contingencies
Preferred securities		87		87
Shareholders’ equity
Common stock		2,388		2,379
Retained earnings		593		559
Accumulated other comprehensive income, net		1		—

Total shareholders’ equity		2,982		2,938

Total liabilities and shareholders’ equity	$	9,353	$	9,156

See the Combined Notes to Consolidated Financial Statements

209

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			Total Shareholders’ Equity
Balance, December 31, 2009	$	2,318	$	(180	)	$	426		$	1		$	2,565
Net Income		—		—			324			—			324
Common stock dividends		—		—			(224	)		—			(224	)
Preferred security dividends		—		—			(4	)		—			(4	)
Repayment of receivable from parent		—		180			—			—			180
Allocation of tax benefit from parent		43		—			—			—			43
Other comprehensive loss, net of income taxes of $(1)		—		—			—			(1	)		(1	)

Balance, December 31, 2010	$	2,361	$	—		$	522		$	—		$	2,883
Net Income		—		—			389			—			389
Common stock dividends		—		—			(348	)		—			(348	)
Preferred security dividends		—		—			(4	)		—			(4	)
Allocation of tax benefit from parent		18		—			—			—			18

Balance, December 31, 2011	$	2,379	$	—		$	559		$	—		$	2,938
Net Income		—		—			381			—			381
Common stock dividends		—		—			(343	)		—			(343	)
Preferred security dividends		—		—			(4	)		—			(4	)
Allocation of tax benefit from parent		9		—			—			—			9
Other comprehensive income, net of income taxes of $0		—		—			—			1			1

Balance, December 31, 2012	$	2,388	$	—		$	593		$	1		$	2,982

See the Combined Notes to Consolidated Financial Statements

210

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Operating revenues
Operating revenues	$	2,725		$	3,060		$	3,534
Operating revenues from affiliates		10			8			7

Total operating revenues		2,735			3,068			3,541

Operating expenses
Purchased power and fuel		973			1,245			1,719
Purchased power from affiliate		396			348			428
Operating and maintenance		622			530			469
Operating and maintenance from affiliates		106			150			126
Depreciation and amortization		298			274			249
Taxes other than income		208			207			200

Total operating expenses		2,603			2,754			3,191

Operating income		132			314			350

Other income and (deductions)
Interest expense		(144	)		(129	)		(131	)
Other, net		23			26			25

Total other income and (deductions)		(121	)		(103	)		(106	)

Income before income taxes		11			211			244
Income taxes		7			75			97

Net income		4			136			147
Preference stock dividends		13			13			13

Net income (loss) on common stock	$	(9	)	$	123		$	134

Comprehensive income	$	4		$	136		$	147

See the Combined Notes to Consolidated Financial Statements

211

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Cash flows from operating activities
Net income	$	4		$	136		$	147
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		298			274			249
Deferred income taxes and amortization of investment tax credits		104			145			299
Other non-cash operating activities		193			129			144
Changes in assets and liabilities:
Accounts receivable		(45	)		60			(95	)
Receivables from and payables to affiliates, net		26			(44	)		(24	)
Inventories		25			(10	)		8
Accounts payable, accrued expenses and other current liabilities		(33	)		(21	)		(66	)
Income taxes		14			35			(56	)
Pension and non-pension postretirement benefit contributions		(16	)		(67	)		(214	)
Other assets and liabilities		(85	)		(161	)		(63	)

Net cash flows provided by operating activities		485			476			329

Cash flows from investing activities
Capital expenditures		(582	)		(592	)		(508	)
Proceeds from the sale of investments and other assets		—			—			21
Changes in intercompany money pool contributions		—			—			315
Change in restricted cash		—			—			(5	)
Other investing activities		9			—			—

Net cash flows used in investing activities		(573	)		(592	)		(177	)

Cash flows from financing activities
Changes in short-term debt		—			—			(46	)
Issuance of long-term debt		250			300			—
Repayment of long-term debt		(173	)		(82	)		(57	)
Dividends paid on common stock		—			(85	)		—
Dividends paid on preference stock		(13	)		(13	)		(13	)
Contributions from parent		66			—			—
Other financing activities		(2	)		(5	)		—

Net cash flows provided by (used in) financing activities		128			115			(116	)

Increase (decrease) in cash and cash equivalents		40			(1	)		36
Cash and cash equivalents at beginning of period		49			50			14

Cash and cash equivalents at end of period	$	89		$	49		$	50

See the Combined Notes to Consolidated Financial Statements

212

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


	December 31,
(In millions)	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	89	$	49
Restricted cash and cash equivalents of variable interest entity		30		30
Accounts receivable, net
Customer		401		428
Other		117		90
Income taxes receivable		3		21
Inventories, net
Gas held in storage		51		74
Materials and supplies		31		34
Deferred income taxes		1		—
Prepaid utility taxes		57		56
Regulatory assets		185		175
Other		8		12

Total current assets		973		969

Property, plant and equipment, net		5,498		5,132
Deferred debits and other assets
Regulatory assets		522		551
Investments		5		—
Investments in affiliates		8		8
Prepaid pension asset		467		514
Other		26		29

Total deferred debits and other assets		1,028		1,102

Total assets	$	7,499	$	7,203

See the Combined Notes to Consolidated Financial Statements

213

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


	December 31,
(In millions)	2012		2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	400	$	110
Long-term debt of variable interest entity due within one year		67		63
Accounts payable		195		210
Accrued expenses		106		110
Deferred income taxes		—		59
Payables to affiliates		65		41
Customer deposits		71		84
Regulatory liabilities		22		19
Other		47		38

Total current liabilities		973		734

Long-term debt		1,446		1,596
Long-term debt to financing trust		258		258
Long-term debt of variable interest entity		265		332
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		1,658		1,491
Asset retirement obligations		8		1
Non-pension postretirement benefits obligations		229		233
Regulatory liabilities		214		201
Other		90		56

Total deferred credits and other liabilities		2,199		1,982

Total liabilities		5,141		4,902

Commitments and contingencies
Shareholders’ equity
Common stock		1,360		1,294
Retained earnings		808		817

Total shareholders’ equity		2,168		2,111

Preference stock not subject to mandatory redemption		190		190

Total equity		2,358		2,301

Total liabilities and shareholders’ equity	$	7,499	$	7,203

See the Combined Notes to Consolidated Financial Statements

214

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY


(In millions)	Common Stock		Retained Earnings			Total Shareholders’ Equity			Preference stock not subject to mandatory redemption		Noncontrolling Interests			Total Equity
Balance, December 31, 2009	$	1,294	$	645		$	1,939		$	190	$	18		$	2,147
Net income		—		147			147			—		—			147
Preference stock dividends		—		(13	)		(13	)		—		—			(13	)
Sale of noncontrolling interest		—		—			—			—		(18	)		(18	)

Balance, December 31, 2010	$	1,294	$	779		$	2,073		$	190	$	—		$	2,263
Net income		—		136			136			—		—			136
Common stock dividends		—		(85	)		(85	)		—		—			(85	)
Preference stock dividends		—		(13	)		(13	)		—		—			(13	)

Balance, December 31, 2011	$	1,294	$	817		$	2,111		$	190	$	—		$	2,301
Net income		—		4			4			—		—			4
Preference stock dividends		—		(13	)		(13	)		—		—			(13	)
Contribution from parent		66		—			66			—		—			66

Balance, December 31, 2012	$	1,360	$	808		$	2,168		$	190	$	—		$	2,358

See the Combined Notes to Consolidated Financial Statements

215

Combined Notes to Consolidated Financial Statements

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

1. Significant Accounting Policies (Exelon, Generation, ComEd, PECO and BGE)

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

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. Prior to March 12, 2012, Exelon’s principal, wholly owned subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger (the “Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customer supply operations. BGE, formerly Constellation’s regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 4—Merger and Acquisitions for further information regarding the merger transaction.

The energy generation business includes:

•

Generation: The integrated business consists of owned and contracted generation and investments in electric generating facilities that are marketed through its leading customer facing activities. The customer facing activities include wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and investments in natural gas exploration and production activities.

The energy delivery businesses include:

•

ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.

•

PECO: 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 services in the Pennsylvania counties surrounding the City of Philadelphia.

•

BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore.

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

This is a combined annual report of Exelon, Generation, ComEd, PECO and BGE. The Notes to the Consolidated Financial Statements apply to Exelon, Generation, ComEd, PECO and BGE as indicated parenthetically next to each corresponding disclosure. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures.

Exelon did not apply push-down accounting to BGE. As a result, BGE continues to maintain its reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2012, 2011 and 2010 and the financial position as of December 31, 2012 and December 31, 2011. However, for Exelon’s consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2012.

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

216

Combined Notes to Consolidated Financial Statements—(Continued)

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

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%, PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred securities and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preference stock. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2012 and December 31, 2011, as equity, PECO’s preferred securities as preferred securities of subsidiary, and BGE’s preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters.

Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for a retail power supply VIE for which Generation has no ownership interest but does have a controlling financial interest through contractual arrangements; 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; and certain Exelon Wind projects, of which Generation holds a majority interest ranging from 94% to 99% for certain periods of time, and the remaining interests are included in noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 for further discussion of Exelon’s and Generation’s VIEs and the reversionary interests of the Noncontrolling members for certain of these projects.

ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2012, as equity.

Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities,

217

Combined Notes to Consolidated Financial Statements—(Continued)

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

revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including the 50.01% interest in CENG, and certain financing trusts of ComEd and PECO. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon’s percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions.

For the year ended December 31, 2012, BGE recorded a $2 million correcting adjustment to reduce electric distribution revenue related to decoupling of 2011 electric distribution revenue, a $3 million correcting adjustment to increase electric operations and maintenance expense related to capitalization of electric transmission costs, and a $5 million correcting adjustment to interest expense to reflect the impacts of amendments of tax positions previously taken on prior-year consolidated income tax returns. BGE has concluded these correcting adjustments are not material to its results of operations or cash flows for the year ended December 31, 2012, or any prior period.

The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.

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

The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. 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, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.

Reclassifications (Exelon, Generation, ComEd, PECO and BGE)

Certain prior year amounts in Exelon’s, Generation’s and BGE’s Consolidated Statements of Cash Flows, Exelon’s, Generation’s, PECO’s, ComEd’s and BGE’s Consolidated Statements of Operations and Comprehensive Income and in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants’ net income or cash flows from operating activities.

Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE)

Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulations, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation

218

Combined Notes to Consolidated Financial Statements—(Continued)

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

that rates are set at levels that will recover the entities’ costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE 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, PECO’s or BGE’s business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3—Regulatory Matters for additional information.

Revenues (Exelon, Generation, ComEd, PECO and BGE)

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. ComEd records its best estimates of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE records its best estimate of the transmission revenue impact resulting from changes in rates that BGE believes are probable of approval by FERC in accordance with its formula rate mechanism. See Notes 3—Regulatory Matters and 5—Accounts Receivable for further information.

RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations, the classification of which depends on the net hourly activity. In addition, capacity revenue and expense classification is based on the net sale or purchase position of the Company in the different RTOs and ISOs.

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 expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. As of the merger date, Exelon and Generation have currently elected to de-designate all of their commodity cash flow hedge positions. Premiums received and paid on option contracts are recognized as revenue or expense over the terms of the contracts. Since ComEd is entitled to full recovery of the costs of the financial swap contract with Generation in rates as settlements occur, ComEd records the fair value of the swap as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. See Note 3—Regulatory Matters for further information.

Proprietary Trading Activities. Exelon and Generation account for Generation’s trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used

219

Combined Notes to Consolidated Financial Statements—(Continued)

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

for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note 10—Derivative Financial Instruments for further discussion.

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

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 have been deferred on the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. In accordance with applicable authoritative guidance, 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 approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position 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 in other income and deductions (interest income) 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 12—Income Taxes for further information.

Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, Generation, ComEd, PECO and BGE)

Exelon, Generation, ComEd, PECO and BGE present any tax assessed by a governmental authority that is the liability of the Registrants and 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 20—Supplemental Financial Information for Generation’s, ComEd’s, PECO’s and BGE’s utility taxes that are presented on a gross basis.

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

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, PECO and BGE)

Restricted cash and investments represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2012 and 2011, Exelon Corporate’s restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, Exelon Corporate has funds restricted for merger commitments. In addition, Exelon Corporate’s investments include its direct financing lease investments. As of December 31, 2012, Generation’s restricted cash and investments primarily included cash at one of its consolidated variable interest entities and, as of 2011, primarily represented funds in escrow related to the acquisition of Shooting Star Wind Project, LLC and cash for payment of certain environmental liabilities. As of December 31, 2012 and 2011, ComEd’s restricted cash primarily represented cash

220

Combined Notes to Consolidated Financial Statements—(Continued)

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

collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As of December 31, 2011, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. As of December 31, 2012 and 2011, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds.

Restricted cash and investments not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2012 and 2011, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2012, Exelon, ComEd, PECO and BGE had short-term investments in Rabbi trusts classified as noncurrent assets.

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

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable agings, historical experience and other currently available information. ComEd and PECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by risk segment. Risk segments represent a group of customers with similar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. BGE estimates the allowance for uncollectible accounts on customer receivables by assigning reserve factors for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. ComEd, PECO and BGE 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, PECO and BGE customer accounts are written off consistent with approved regulatory requirements. ComEd’s, PECO’s and BGE’s provisions for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3—Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.

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

Exelon accounts for its investments in and arrangements with VIEs based on the authoritative guidance which includes the following specific requirements:

•

requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,

•

requires an ongoing reconsideration of this assessment instead of only upon certain triggering events,

•

amends the events that trigger a reassessment of whether an entity is a VIE, and

•

requires the entity that consolidates a VIE (the primary beneficiary) to present separately on the face of its balance sheet (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

221

Combined Notes to Consolidated Financial Statements—(Continued)

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

Based on the above accounting guidance, Exelon has adopted the following policies related to variable interest entities:

•

Exelon has presented separately on its Consolidated Balance Sheets, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of Exelon’s consolidated VIEs for which creditors do not have recourse to Exelon’s general credit.

•

Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantly impact the entity. Exelon has evaluated all existing entities under the new VIE accounting requirements, both those previously considered VIEs and those considered potential VIEs. Exelon’s accounting for and disclosure about VIEs did not change materially as a result of these assessments.

See Note 2—Variable Interest Entities for additional information.

Inventories (Exelon, Generation, ComEd, PECO and BGE)

Inventory is recorded at the lower of weighted average 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 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 weighted average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and expensed or capitalized to property, plant and equipment, as appropriate, when installed or used.

Emission Allowances. Emission allowances are included in inventory (for emission allowances exercisable in the current year) and other deferred debits (for emission allowances that are exercisable beyond one year) and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations.

Marketable Securities (Exelon, Generation, ComEd, PECO and BGE)

All marketable securities are reported at fair value. Marketable securities held in the NDT funds and BGE’s Rabbi trust investments are classified as trading securities and all other securities are classified 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, the Zion generating station and portions of the Peach Bottom nuclear generating units not subject to a regulatory agreement (Non-Regulatory Agreement Units) are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on BGE’s Rabbi trust investments are included in earnings at Exelon and BGE. 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

222

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 13— Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 20—Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities.

Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)

Property, plant and equipment is recorded at original cost. Original cost includes labor, materials and construction overhead. When appropriate, original cost also includes capitalized interest for Generation and Exelon Corporate and AFUDC for regulated property at ComEd, PECO and BGE. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to maintenance expense as incurred. For constructed assets, Exelon capitalizes construction-related direct labor and material costs. ComEd, PECO and BGE also capitalized indirect construction costs including labor and related costs of departments associated with supporting construction activities.

Third parties reimburse ComEd, PECO and BGE for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, Plant and Equipment. DOE SGIG funds reimbursed to PECO and BGE are accounted for as CIAC.

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, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to operating and maintenance expense as incurred.

For ComEd, PECO and BGE, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd’s and BGE’s depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility’s regulatory recovery method. ComEd’s and BGE’s actual incurred removal costs are applied against a 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.

Generation’s oil and gas exploration and production activities consist of working interests in gas producing fields. Generation accounts for these activities under the successful efforts method of accounting. Acquisition, development and exploration costs are capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred.

See Note 6—Property, Plant and Equipment, Note 7—Jointly Owned Electric Utility Plant and Note 20—Supplemental Financial Information for additional information regarding property, plant and equipment.

223

Combined Notes to Consolidated Financial Statements—(Continued)

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

Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. The estimated disposal cost of SNF is established per the Standard Waste Contract with the DOE and is expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. On-site SNF storage costs are capitalized or expensed to operating and maintenance expense as incurred based upon the nature of the costs. 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.

Nuclear Outage Costs (Exelon and Generation)

Costs associated with nuclear outages, including planned major maintenance activities, are expensed to operating and maintenance expense or capitalized to property, plant and equipment (based on the nature of the activities) 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 facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management’s determination that the project is economically and operationally feasible, management and/or the Exelon Board of Directors has approved the project and has 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. Upon commencement of construction, these costs will be charged to construction work in progress. Capitalized development costs are charged to operating and maintenance expense when project completion is no longer probable. At December 31, 2012 and 2011, Exelon’s and Generation’s capitalized development costs totaled approximately $1.2 billion and $376 million, respectively, which are included in Property, Plant and Equipment on Exelon’s and Generation’s Consolidated Balance Sheets. Costs included in the balance as of December 31, 2012 primarily relate to the development of the Antelope Valley project along with other, smaller renewable energy projects. See Note 4—Merger and Acquisitions for additional information on Antelope Valley. Costs included in the balance as of December 31, 2011 primarily relate to land rights and other third-party costs directly associated with the development of certain Exelon Wind projects. Approximately $4 million, $2 million and $6 million of costs were expensed by Exelon and Generation for the years ended December 31, 2012, 2011 and 2010, respectively. These costs primarily related to the possible development of new renewable energy projects.

224

Combined Notes to Consolidated Financial Statements—(Continued)

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

Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE)

Costs incurred during the application development stage of software projects that are internally developed or purchased for operational 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 based on the expected life or pursuant to prescribed regulatory requirements. 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		BGE
December 31, 2012	$	499	$	143	$	105	$	63	$	157
December 31, 2011		280		82		120		67		62

Amortization of capitalized software costs	Exelon ^(a)		Generation^(a)		ComEd		PECO		BGE ^(a)
2012	$	208		$81		$56	$	30		$32
2011		122		41		50		25		25
2010		104		33		41		19		26

(a)

Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010.

Depreciation, Depletion and Amortization (Exelon, Generation, ComEd, PECO and BGE)

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 and BGE’s depreciation includes a provision for estimated removal costs as authorized by the respective regulators. The estimated service lives for ComEd, PECO and BGE 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 except for Oyster Creek. 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. The estimated service lives of the fossil fuel and other renewable generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments taking into account economic and capital requirement considerations.

See Note 6—Property, Plant and Equipment for further information regarding depreciation.

Depletion of oil and gas exploration and production activities is recorded using the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for gas reserves are based on internal calculations.

Amortization of regulatory assets is recorded over the recovery period specified in the related legislation or regulatory agreement and is included in depreciation and amortization expense on ComEd’s, PECO’s and BGE’s Consolidated Statements of Operations and Comprehensive Income.

225

Combined Notes to Consolidated Financial Statements—(Continued)

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

See Note 3—Regulatory Matters and 20—Supplemental Financial Information for additional information regarding Generation’s nuclear fuel, Generation’s ARC and the amortization of ComEd’s, PECO’s and BGE’s regulatory assets.

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

The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be 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 that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, 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 13—Asset Retirement Obligations for additional information.

Capitalized Interest and AFUDC (Exelon, Generation, ComEd, PECO and BGE)

During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.

Exelon, ComEd, PECO and BGE 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 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.

226

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:


		Exelon^(a)		Generation ^(a)		ComEd		PECO		BGE^(a)
2012	Total incurred interest^(b)	$	1,003	$	368	$	310	$	125	$	149
	Capitalized interest		67		67		—		—		—
	Credits to AFUDC debt and equity		25		—		9		6		15

2011	Total incurred interest^(b)	$	783	$	219	$	349	$	138	$	136
	Capitalized interest		49		49		—		—		—
	Credits to AFUDC debt and equity		25		—		12		13		22

2010	Total incurred interest^(b)	$	861	$	191	$	388	$	197	$	137
	Capitalized interest		38		38		—		—		—
	Credits to AFUDC debt and equity		16		—		5		11		16

(a)

(b)	Includes interest expense to affiliates.

Guarantees (Exelon, Generation, ComEd, PECO and BGE)

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 19—Commitments and Contingencies for additional information.

Asset Impairments (Exelon, Generation, ComEd, PECO and BGE)

Long-Lived Assets. The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Cash flows from Generation plant assets are evaluated at a regional portfolio level along with cash flows generated from Generation’s supply and risk management activities, including cash flows from contracts that are recorded as intangible contract assets and liabilities on the balance sheet. For ComEd, PECO, and BGE, 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 provided. For ComEd, the lowest level of independent cash flows is transmission and distribution and, for PECO and BGE, the lowest level of independent cash flows is transmission, distribution and gas.

An impairment loss is recorded if the undiscounted expected future cash flows are less than the carrying amount of the long-lived asset or asset group. The amount of the impairment loss recorded is the difference between the estimated fair value of the long-lived asset or asset group and the carrying value.

227

Combined Notes to Consolidated Financial Statements—(Continued)

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

Conditions that could have an adverse impact on the expected future cash flows and the fair value of the long-lived assets and asset groups include, among other factors, a deteriorating business climate, including current energy and market conditions, revisions to regulatory laws, or plans to dispose of a long-lived asset significantly before the end of its useful life.

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 would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 8—Intangible Assets for additional information regarding Exelon’s and ComEd’s goodwill.

Equity Method Investments. Exelon and Generation evaluate equity method investments to determine whether or not they are impaired. An impairment must be recorded when the investment has experienced an other than temporary decline in value. Additionally, if the project in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other than temporary decline in value. Exelon and Generation continuously monitor issues that potentially could impact future profitability of the equity method investments.

Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)

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 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 derivative contracts intended to serve as economic hedges and that do not qualify or are not designated for hedge accounting or the normal purchases and normal sales exception, 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 Statement of Operations based on the activity the transaction is economically hedging. 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. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statement 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 Statements of Cash Flows, depending on the nature of each transaction.

For derivative commodity contracts, effective with the date of the merger with Constellation, Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of

228

Combined Notes to Consolidated Financial Statements—(Continued)

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

Constellation’s designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivatives executed to hedge economic risk for commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company.

Revenues and expenses on derivative 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 rather are recorded 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 will not be financially settled. 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 energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the applicable requirements, 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, PECO and BGE. See Note 10—Derivative Financial Instruments for additional information.

Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective March 12, 2012, Exelon became the sponsor of all of Constellation’s defined benefit pension and other postretirement benefit plans and defined contribution savings plans.

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 or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 14—Retirement Benefits for additional discussion of Exelon’s accounting for retirement benefits.

Equity Investment Earnings (Losses) of Unconsolidated Affiliates (Exelon and Generation)

Exelon and Generation include equity in earnings from equity method investments in qualifying facilities, power projects and joint ventures, including Generation’s 50.01% interest in CENG, in equity in earnings (losses) of unconsolidated affiliates. Equity in earnings (losses) of unconsolidated affiliates also includes any adjustments to amortize the difference, if any, except for goodwill and land, between their cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment. See Note 22—Related Party Transactions for additional discussion of Exelon’s and Generation’s investment in CENG.

Exelon and Generation continuously monitor for issues that potentially could impact future profitability of these equity method investments and which could result in the recognition of an impairment loss if such investment experiences an other than temporary decline in value.

229

Combined Notes to Consolidated Financial Statements—(Continued)

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

New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)

Exelon has identified the following new accounting pronouncements that have been recently adopted or issued that may affect the Registrants.

Fair Value Measurement

In May 2011, the FASB issued authoritative guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. The new guidance does not impact the fair value measurements included in the Registrant’s Consolidated Financial Statements as of December 31, 2012. The guidance was effective for the Registrants beginning with the period ended March 31, 2012 and was required to be applied prospectively. The Company updated the existing fair value disclosures during the first quarter of 2012 to comply with the new requirements for this standard. See Note 9—Fair Value of Financial Assets and Liabilities for new disclosures.

Statement of Comprehensive Income

In June 2011, the FASB issued authoritative guidance requiring entities to present net income and other comprehensive income in a single continuous statement of comprehensive income or in two separate, but consecutive, statements. The new guidance does not change the components that are recognized in net income and the components that are recognized in other comprehensive income. This guidance became effective for the Registrants for periods beginning after December 15, 2011 and was required to be applied retroactively. Each of the Registrants currently presents a single statement of comprehensive income, consistent with the new guidance.

Presentation of Items Reclassified out of Accumulated Other Comprehensive Income

In February 2013, the FASB issued authoritative guidance requiring entities to present either in the notes or parenthetically on the face of the financial statements, reclassifications from each component of accumulated other comprehensive income and the impacted income statement line items. Entities only need to disclose the impacted income statement line item for components reclassified to net income in their entirety; otherwise, a cross-reference to the related note should be provided. This guidance is effective for the Registrants for periods beginning after December 15, 2012 and is required to be applied prospectively. 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.

Disclosures About Offsetting Assets and Liabilities

In December 2011 (and amended in January 2013), the FASB issued authoritative guidance requiring entities to disclose both gross and net information about recognized derivative instruments, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing or lending transactions that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. This guidance is effective for the Registrants for periods beginning on or after January 1, 2013 and is required to be applied retrospectively. This guidance is primarily applicable to certain derivative transactions for Exelon and Generation. 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.

230

Combined Notes to Consolidated Financial Statements—(Continued)

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

2. Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)

Under the applicable authoritative guidance, a VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly impact the entity’s economic performance.

As of December 31, 2012, the Registrant’s consolidated five VIEs or VIE groups for which the Registrants were the primary beneficiary, and the Registrants had significant interests in nine other VIEs for which the Registrants do not have the power to direct the entities’ activities and, accordingly, were not the primary beneficiary.

Consolidated Variable Interest Entities

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financial statements at December 31, 2012 and 2011 are as follows:


	December 31, 2012						December 31, 2011
	Exelon ^(a)		Generation		BGE ^(b)		Exelon		Generation		BGE ^(b)
Current assets	$	550	$	519	$	30	$	15	$	15	$	30
Noncurrent assets		1,802		1,762		—		784		784		—

Total assets	$	2,352	$	2,281	$	30	$	799	$	799	$	30

Current liabilities	$	685	$	613	$	71	$	181	$	181	$	69
Noncurrent liabilities		837		532		265		77		77		332

Total liabilities	$	1,522	$	1,145	$	336	$	258	$	258	$	401

(a)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

(b)	Amounts related to BGE are presented for the standalone entity as of both December 31, 2012 and 2011.

Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the preceding table can only be settled using VIE resources.

RSB BondCo LLC. In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1. BGE determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE consolidated BondCo.

BondCo’s assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During 2012, 2011, and 2010, BGE remitted $85 million, $92 million, and $90 million, respectively, to BondCo.

231

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE did not provide any additional financial support to BondCo during 2012 or 2011. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.

Retail Gas Group. During 2009, Constellation formed two new entities, which now are part of Generation, and combined them with its existing retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third party gas supplier. While Generation owns 100% of these entities, it has been determined that the retail gas entity group is a VIE because there is not sufficient equity to fund the group’s activities without the additional credit support that is provided in the form of a parental guarantee. Generation is the primary beneficiary of the retail gas entity group; accordingly, Generation consolidates the retail gas entity group as a VIE.

The third party gas supply arrangement is collateralized as follows:

•

The assets of the retail gas entity group must be used to settle obligations under the third party gas supply agreement before it can make any distributions to Generation,

•

The third party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and

•

As of December 31, 2012, Exelon provided a $75 million parental guarantee to the third party gas supplier in support of the retail gas entity group.

Other than credit support provided by the parental guarantee, Exelon or Generation do not have any contractual or other obligations to provide additional financial support under the collateralized third party gas supply agreement. The third party gas supply creditors do not have any recourse to Exelon’s or Generation’s general credit other than the parental guarantee.

Retail Power Supply Entity. Generation also consolidates a retail power supply VIE for which Constellation became the primary beneficiary in 2008 as a result of a modification to its contractual arrangements that changed the allocation of the economic risks and rewards of the VIE among the variable interest holders. This entity now sits under Generation Consolidated and the consolidation of this VIE did not have a material impact on Generation’s financial results or financial condition.

Solar Project Entity Group. In 2011, Constellation formed a group of solar project limited liability companies to build, own, and operate solar power facilities which are now part of Generation. Additionally, on September 30, 2011, Generation acquired all of the equity interests in Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project in northern Los Angeles County, California, from First Solar Inc. While Generation owns 100% of these entities, it has been determined that certain of the individual solar project entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the solar project entities that qualify as VIEs because Generation controls the design, construction, and operation of the solar power facilities. Generation provides capital funding to these solar VIE entities for ongoing construction of the solar power facilities. In addition, these solar VIE entities have an aggregate amount of debt with third parties of $220 million for which the creditors have recourse to Generation.

232

Combined Notes to Consolidated Financial Statements—(Continued)

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

Wind Project Entity Group. Generation owns and operates a number of wind project limited liability entities, the majority of which were acquired on December 9, 2010 when Generation completed the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind). Generation has evaluated the significant agreements and ownership structures and risks of each of its wind projects and underlying entities, and determined that certain of the entities are VIEs because either the projects have noncontrolling interest holders that absorb variability from the wind projects, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the wind project entities that qualify as VIEs because Generation controls the design, construction, and operation of the wind power facilities. While Generation owns 100% of the majority of the wind project entities, 10 of the projects have noncontrolling equity interests held by third parties, that currently range between 1% and 6%. Of these 10 projects, Generation’s current economic interests in nine of the projects are significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the non-controlling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the non-controlling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation is to provide financial support to the projects in proportion to its current economic interests in the projects that currently range between 94% and 99%. However, no additional support to these projects beyond what was contractually required has been provided during 2012. As of December 31, 2012, the carrying amount of the assets and liabilities that are consolidated as a result of Generation being the primary beneficiary of the wind VIE entities primarily relate to the wind generating assets, PPA intangible assets and working capital amounts.

Unconsolidated Variable Interest Entities

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include three transaction types: (1) equity method investments, (2) energy purchase and sale contracts, and (3) fuel purchase commitments. For the equity method investments, the carrying amount of the investments is reflected on their Consolidated Balance Sheets in investments in affiliates. For the energy purchase and sale contracts and the fuel purchase commitments (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided or guaranteed the debt or equity support, or provided liquidity arrangements, performance guarantees or other commitments associated with these commercial agreements.

233

Combined Notes to Consolidated Financial Statements—(Continued)

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

As of December 31, 2012, Exelon and Generation did have significant variable interests in and exposure to loss associated with nine VIEs for which they were not the primary beneficiary; including certain equity method investments and certain commercial agreements. As of December 31, 2011, Exelon and Generation had a significant variable interest in and exposure to loss associated with one VIE for which they were not the primary beneficiary. The following tables present summary information about the significant unconsolidated VIE entities for which Exelon and Generation have exposure to loss:


December 31, 2012	Commercial Agreement VIEs		Equity Method Investment VIEs		Total
Total assets ^(a)	$	386	$	354	$	740
Total liabilities ^(a)		219		114		333
Registrants’ ownership interest ^(a)		—		97		97
Other ownership interests ^(a)		167		143		310
Registrants’ maximum exposure to loss:
Letters of credit		5		—		5
Carrying amount of equity method investments		—		77		77
Contract intangible asset		8		—		8
Debt and payment guarantees		—		5		5
Net assets pledged for Zion Station decommissioning ^(b)		50		—		50

December 31, 2011	Commercial Agreement VIEs		Equity Method Investment VIEs		Total
Registrants’ maximum exposure to loss:
Net assets pledged for Zion Station decommissioning ^(b)		43		—		43

(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

(b)

These items represent amounts on Generation’s and Exelon’s balance sheet related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $614 million and $734 million as of December 31, 2012 and December 31, 2011, respectively; offset by payables to ZionSolutions LLC of $564 million and $691 million as of December 31, 2012 and December 31, 2011, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 13—Asset Retirement Obligations for further discussion.

Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these variable interest entities.

Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sells power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. In connection with this transaction, a third party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder

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Combined Notes to Consolidated Financial Statements—(Continued)

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

could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation is not required.

ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 13— Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required.

Fuel Purchase Commitments. Generation’s customer supply 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 Note 19—Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required.

For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities’ activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is 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. 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 and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19—Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required.

ComEd, PECO and BGE

ComEd’s, PECO’s, and BGE’s retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3—Regulatory Matters and Note 19—Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required.

For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most

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Combined Notes to Consolidated Financial Statements—(Continued)

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

significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd’s, PECO’s, and BGE’s Consolidated Balance Sheets that relate to their involvement with VIEs generally represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2012, the total amount of accounts payable owed by the utilities under agreements with VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in any VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 19—Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements.

PECO

PETT, a financing trust, was created in 1998 by PECO to purchase and own intangible transition property (ITP) and to issue transition bonds to securitize $5 billion of PECO’s stranded cost recovery authorized by the PAPUC pursuant to the Competition Act. PETT was consolidated in Exelon’s and PECO’s financial statements on January 1, 2010 pursuant to authoritative guidance relating to the consolidation of VIEs that became effective on that date. Under the guidance, PECO concluded that it was the primary beneficiary of PETT due to PECO’s involvement in the design of PETT, its role as servicer, and its right to dissolve PETT and receive any of its remaining assets following retirement of the transition bonds and payment of PETT’s other expenses. The consolidation of PETT did not have a significant impact on PECO’s results of operations or statement of cash flows. Upon retirement of the outstanding transition bonds on September 1, 2010, the remaining cash balance was remitted to PECO, and PETT was dissolved on September 20, 2010.

3. Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)

The following matters below discuss the current status of material regulatory and legislative proceedings of the Registrants.

Illinois Regulatory Matters

Energy Infrastructure Modernization Act (Exelon and ComEd).

Background

EIMA provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois’ electric utility infrastructure. EIMA allows the recovery of costs by a utility through a pre-established performance-based formula rate tariff, approved by the ICC. ComEd made an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund on July 31, 2012, and will make recurring annual contributions of $4 million, the first of which was made on December 31, 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates. These contributions also began in 2012.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Formula Rate Tariff

On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of that proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June 2012. On May 29, 2012, the ICC issued an Order (May Order) in that proceeding. The May Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than proposed by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC’s determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in a subsequent annual reconciliation, thereby primarily delaying the timing of cash flows. The incremental revenue reduction also reflected a $35 million reduction for the disallowance of return on ComEd’s pension asset, a $10 million reduction for incentive compensation related adjustments, and $15 million of reductions for various adjustments for cash working capital, operating reserves, and other technical items. In the second quarter of 2012, ComEd recorded a total reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for 2011 and for the first three months of 2012 consistent with the terms of the May Order.

On June 22, 2012, the ICC granted an expedited rehearing on some of the issues raised by the May Order, including ComEd’s pension asset recovery. On October 3, 2012, the ICC issued its final order (Rehearing Order) in that rehearing, adopting ComEd’s position on the return on its pension asset, resulting in an increase in ComEd’s annual revenue requirement. In two other areas, the ICC ruled against ComEd by reaffirming use of an average rather than year-end rate base in ComEd’s reconciliation revenue requirement; and amending its prior order to provide a short-term debt rate as the appropriate interest rate to apply to under/over recoveries of incurred costs. ComEd filed an appeal of the May Order and the Rehearing Order in court on October 4, 2012. In the fourth quarter of 2012 ComEd recorded an increase in revenue of approximately $135 million pre-tax consistent with the terms of the Rehearing Order, of which $75 million pre-tax reflects the reinstatement of the 2011 return on pension asset and $60 million pre-tax reflects the return on pension asset costs for 2012. New rates reflecting the impacts of the Rehearing Order went into effect in November 2012.

Capital Investment

On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under that plan, ComEd will invest approximately $2.6 billion over ten years to modernize and storm-harden its distribution system and to implement smart grid technology. These investments will be incremental to ComEd’s historical level of capital expenditures. The filing with the ICC specifically included ComEd’s $233 million investment plan for 2012. On April 23, 2012, ComEd filed its initial AMI Deployment Plan with the ICC. On June 22, 2012, the ICC approved the AMI Deployment Plan with certain modifications. However, as a result of the Rehearing Order above, ComEd is delaying certain elements of the AMI Deployment Plan, including the installation of additional smart meters. ComEd outlined the new deployment schedule within testimony provided in the AMI Plan Rehearing on October 3, 2012. As a result of the Rehearing Order, ComEd has deferred approximately $50 million of the 2012 AMI Deployment Plan and $15 million of 2012 planned capital investment to future years. On December 5, 2012, the ICC approved ComEd’s revised AMI deployment plan. Under the AMI deployment schedule, ComEd will be taking meters out of service prior to the end of their original service lives, which resulted in recording accelerated depreciation for the remaining carrying value of the meters. The Order provides for full recovery of the cost of these early retired meters and, therefore, ComEd recorded a regulatory asset of $7 million for the accelerated depreciation of these meters in the fourth quarter of 2012.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Annual Reconciliation

ComEd will file an annual reconciliation of the revenue requirement in effect in a given year to reflect actual costs that the ICC determines are prudently and reasonably incurred for such year. ComEd made its initial 2011 reconciliation filing on April 30, 2012, which reconciled the 2011 revenue requirement in effect to ComEd’s actual 2011 costs incurred. The ICC’s final order, issued on December 20, 2012, increased the revenue requirement by $73 million, in conformity with the formula rate structure provided in the May and Rehearing Orders. The rates took effect in January 2013. A similar reconciliation with respect to 2012 will be filed in second quarter 2013 with any adjustments to rates taking effect in January 2014. As of December 31, 2012, and December 31, 2011, ComEd recorded a net regulatory asset of $209 million and $84 million, respectively, reflecting ComEd’s best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred, consistent with the ICC’s approved distribution formula rate structure per the May and Rehearing Orders.

Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via a rider (Rider SMP).

The Court held the ICC abused its discretion in not reducing ComEd’s rate base to account for an additional 18 months of accumulated depreciation while including post-test year pro forma plant additions through that period (the same position ComEd took in its 2010 electric distribution rate case (2010 Rate Case) discussed below). ComEd continued to bill rates as established under the ICC’s order in the 2007 Rate Case until June 1, 2011, when the rates set in the 2010 Rate Case became effective. In August 2011, ComEd filed testimony in the remand proceeding that no refunds should be required. The ICC subsequently initiated a proceeding on remand. On February 23, 2012, the ICC issued an order on remand in the proceeding requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation issue. On March 26, 2012, ComEd filed a notice of appeal with the Court.

ComEd has recognized for accounting purposes its best estimate of any refund obligation, as discussed above.

Advanced Metering Program Proceeding (Exelon and ComEd) In October 2009, the ICC approved a modified version of ComEd’s system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Attorney General, appealed the ICC’s order on Rider AMP. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of other costs from recovery under Rider AMP to recovery through electric distribution rates. On March 19, 2012, the Court reversed the ICC’s approval of Rider AMP, concluding that the ICC’s October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012. The Illinois Supreme Court denied the Petition on September 26, 2012, and returned the matter to the ICC to calculate a refund amount. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Court’s order on March 19, 2012, and should not have a material impact on ComEd and Exelon.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

2010 Illinois Electric Distribution Rate Case (Exelon and ComEd). On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its annual delivery services revenue requirement. This request was subsequently reduced to $343 million to account for changes in tax law, corrections, acceptance of limited adjustments proposed by certain parties and the amounts expected to be recovered in the AMI pilot program tariff discussed above. The request to increase the annual revenue requirement was to allow ComEd to recover the costs of substantial investments made since its last rate filing in 2007. The requested increase also reflected increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The original requested rate of return on common equity was 11.5%. In addition, ComEd requested future recovery of certain amounts that were previously recorded as expense that would allow ComEd to recognize a one-time benefit of up to $40 million (pre-tax). The requested increase also included $22 million for increased uncollectible accounts expense, which would increase the threshold for determining over/under recoveries under ComEd’s uncollectible accounts tariff.

On May 24, 2011, the ICC issued an order in ComEd’s 2010 rate case, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd’s annual delivery services revenue requirement and a 10.5% rate of return on common equity. As expected, the ICC followed the Court’s position on the post-test year accumulated depreciation issue. The order allowed ComEd to establish or reestablish a net amount of approximately $40 million of previously expensed plant balances or new regulatory assets, which is reflected as a reduction in operating and maintenance expense and income tax expense for the year ended December 31, 2012. The order also affirmed the current regulatory asset for severance costs, which was challenged by an intervener in the 2010 Rate Case. The order has been appealed to the Court by several parties. ComEd cannot predict the result of these appeals.

Utility Consolidated Billing and Purchase of Receivables (Exelon and ComEd). In November 2008, the Illinois Public Utilities Act was amended to require ComEd to file tariffs establishing Utility Consolidated Billing and Purchase of Receivables services. On December 15, 2010, the ICC approved ComEd’s tariff offering Purchase of Receivables with Consolidated Billing (PORCB) services for RES. Since the first quarter of 2011, ComEd has been required to buy certain RES receivables, primarily residential and small commercial and industrial customers, at the option of the RES, for electric supply service and then include those amounts on ComEd’s bill to customers. Receivables are purchased at a discount to compensate ComEd for uncollectible accounts. ComEd produces consolidated bills for the aforementioned retail customers reflecting charges for electric delivery service and purchased receivables. As of December 31, 2012, the balance of purchased accounts receivable associated with PORCB was $55 million. Under the tariff, ComEd recovers from RES and customers the costs for implementing and operating the program. A number of municipalities, including the City of Chicago, have announced their intention to switch to RES electric supply as a result of referenda voted on in November 2012. The City of Chicago switching will occur in the first quarter of 2013. The other municipalities are expected to switch during the first half of 2013. As a result, ComEd expects a significant increase in the amount of RES receivables it will be required to purchase in 2013.

Recovery of Uncollectible Accounts (Exelon and ComEd). On February 2, 2010, the ICC issued an order adopting tariffs for ComEd to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually. As a result of the ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense in the first quarter of 2010 for the cumulative under-collections in 2008 and 2009. In addition, ComEd recorded a one-time charge of $10 million to operating and maintenance expense in the first quarter of 2010 for a contribution to the Supplemental Low-Income Energy Assistance Fund, which is used to assist low-income residential customers.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement Legislation, ComEd hedged the price of a significant portion of energy purchased in the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. On February 17, 2012, the ICC approved the IPA’s procurement plan covering the period June 2012 through May 2017. As of December 31, 2012, ComEd had completed the ICC-approved procurement process for its energy requirements through May 2013 as well as a portion of its requirements for each of the procurement periods ending in May 2014 and May 2015.

EIMA discussed above contains a provision for the IPA to conduct procurement events for energy and REC requirements for the June 2013 through December 2017 period. The procurement events mandated under EIMA were completed during February 2012.

The Illinois Settlement Legislation discussed below requires ComEd to purchase an increasing percentage of its electricity requirements from renewable energy resources. On December 17, 2010, ComEd entered into 20-year contracts with several unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. The long-term renewables purchased will count towards satisfying ComEd’s obligation under the state’s RPS and all associated costs will be recoverable from customers. As of December 31, 2012, ComEd has completed the ICC-approved procurement process for RECs through May 2013. See Note 10—Derivative Financial Instruments for additional information regarding ComEd’s financial swap contract with Generation and long-term renewable energy contracts.

On December 19, 2012, the ICC issued an order directing ComEd and Ameren (the Utilities) to enter into sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The proposed term of the agreement is 20 years. The development was approved by the DOE on February 4, 2013. The sourcing agreement is currently being drafted and approved under a separate proceeding, with a final order expected in 2013. The sourcing agreement is expected to stipulate that the Utilities will pay (or receive) the difference between FutureGen’s contract prices and the revenues FutureGen receives for capacity and energy from bidding the unit into the MISO markets. The order also directs the Utilities to recover (or pass along) the difference from the Utilities’ distribution system customers, regardless of whether they purchase electricity from the Utility or from an alternative electric generation supplier. On January 22, 2013, ComEd filed an application for rehearing, requesting the ICC reconsider its December order by expanding the parties to the sourcing agreement to also include RES suppliers. On January 29, 2013, the ICC denied ComEd’s rehearing request. Depending on the precise terms of the sourcing agreement, the eventual market conditions, and the manner of cost recovery, the sourcing agreement could have a material adverse impact on Exelon’s and ComEd’s cash flows and financial positions.

On December 19, 2012, the ICC approved the IPA’s 2013 procurement plan. In response to the increased number of ComEd’s customers purchasing their energy from alternative energy suppliers on their own or through municipal aggregation, the plan does not propose any new REC procurements for the period June 2013—May 2014. Additionally, the IPA plan provides that curtailment of the existing long-term contracts for renewable energy and RECs be considered. The ICC concluded that the

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Combined Notes to Consolidated Financial Statements—(Continued)

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

magnitude of this curtailment shall be determined based upon the March 2013 forecast update and that any such reduction shall be applied proportionately to each of the long-term contracts consistent with the terms of the contracts on an equal, pro-rata basis.

Illinois Settlement Legislation (Exelon, Generation and ComEd). The Illinois Settlement Legislation was signed into law in August 2007 following a settlement resulting from extensive discussions with legislative leaders in Illinois, ComEd, Generation and other utilities and generators in Illinois to address concerns about higher electric bills 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. Various Illinois electric utilities, their affiliates and generators of electricity agreed to contribute approximately $1 billion over a period of four years that ended in 2010 to programs to provide rate relief to Illinois electricity customers and funding for the IPA. 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, approximately $308 million for rate relief programs for customers of other Illinois utilities and approximately $5 million for partially funding operations of the IPA. The contributions were recognized in the financial statements of Generation and ComEd as rate relief credits were applied to customer bills by ComEd and other Illinois utilities or as operating expenses associated with the programs were incurred. As of December 31, 2010, Generation and ComEd had fulfilled their commitments under the Illinois Settlement Legislation.

During 2010, Generation and ComEd recognized net costs from their contributions pursuant to the Illinois Settlement Legislation in their Consolidated Statements of Operations as follows:


Year Ended December 31, 2010	Generation		ComEd		Total Credits Issued to ComEd Customers
Credits to ComEd customers^(a)	$	14	$	1	$	15
Credits to other Illinois utilities’ customers^(a)		7		n/a		n/a

Total incurred costs	$	21	$	1	$	15

(a)	Recorded as a reduction in operating revenues.

Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). As a result of the Illinois Settlement Legislation, 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 2.0% of energy delivered in the year commencing June 1, 2015 and each year thereafter. 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 initial three-year Energy Efficiency and Demand Response Plan, including cost recovery, covering the period from June 2008 through May 2011. In December 2010, the ICC approved ComEd’s second three-year Energy Efficiency and Demand Response Plan covering the period June 2011 through May 2014. The plans are designed to meet the Illinois Settlement Legislation’s energy efficiency and demand response goals through May 2014, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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. All goals are subject to rate impact criteria set forth in the Illinois Settlement Legislation. As of December 31, 2012, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois Settlement Legislation. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates. See Note 19—Commitments and Contingencies for information regarding ComEd’s future commitments for the procurement of RECs.

Pennsylvania Regulatory Matters

2010 Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On December 16, 2010, the PAPUC approved the settlement of PECO’s electric and natural gas distribution rate cases, which were filed in March 2010, providing increases in annual service revenue of $225 million and $20 million, respectively. The electric settlement provides for recovery of PJM transmission service costs on a full and current basis through a rider. The approved electric and natural gas distribution rates became effective on January 1, 2011.

In addition, the settlements included a stipulation regarding how tax benefits related to the application of any new IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements require that the expected cash benefit from the application of any new guidance to tax years prior to 2011 be refunded to customers over a seven-year period. On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECO adopted the safe harbor and elected a method change for the 2010 tax year. The expected total refund to customers for the tax cash benefit from the application of the safe harbor to costs incurred prior to 2010 is $171 million. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to execute the refund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return, which is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2012.

In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The expected total refund to customers for the tax cash benefit from the application of the new method to costs incurred prior to 2011 is $54 million. This amount is subject to adjustment based on the outcome of IRS examinations. Credits will be reflected in customer bills beginning January 1, 2013. PECO currently anticipates that the IRS will issue guidance in 2013 providing a safe harbor method of accounting for gas transmission and distribution property.

The prospective tax benefits claimed as a result of the new methodology will be reflected in tax expense in the year in which they are claimed on the tax return and will be reflected in the determination of revenue requirements in the next electric and natural gas distribution rate cases. See Note 12 for additional information.

The 2010 electric and natural gas distribution rate case settlements did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. PECO has not filed a transmission rate case since rates have been unbundled.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Pennsylvania Procurement Proceedings (Exelon and PECO). PECO’s current PAPUC approved DSP Program, under which PECO is providing default electric service, has a 29-month term that began on January 1, 2011 and ends May 31, 2013. On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO’s second DSP Program, which was filed with the PAPUC in January 2012. The program, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129. Under the DSP Programs, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. In addition, PECO’s second DSP Program provides for the recovery of AEPS compliance costs through the GSA rather than a separate AEPS rider. The filing and implementation costs of the current and second DSP Programs were recorded as regulatory assets and are being recovered through the GSA over the DSP Programs 29-month and 24-month terms, respectively.

During 2012, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its last three competitive procurements under the DSP Program for electric supply for default electric service. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Statement of Operations and Comprehensive Income.

In the second DSP Program, PECO will procure electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes will be served through competitively procured fixed price, full requirements contracts of two years or less. Similar to the current DSP Program, for the large commercial and industrial class load, PECO will competitively procure contracts for full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes beginning in June 2013.

In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning April 1, 2014. PECO expects to file its plan for CAP customers by May 1, 2013.

Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009, in April 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million smart meters and an AMI communication network by 2020. The first phase of PECO’s SMPIP included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On January 18, 2013, PECO filed with the PAPUC its universal deployment plan for approval of its proposal to deploy the remainder of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $120 million on smart grid investments through 2014 before considering the DOE reimbursements discussed below. As of December 31, 2012, PECO has spent $241 million and $100 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received to date.

243

Combined Notes to Consolidated Financial Statements—(Continued)

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

Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in non-taxable SGIG funds of which $140 million relates to smart meter deployment and $60 million relates to smart grid infrastructure. As part of the agreement, the DOE has a conditional ownership interest in qualifying Federally-funded project property and equipment, which is subordinate to PECO’s existing mortgage. The SGIG funds are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of December 31, 2012, PECO has received $144 million of the $200 million in reimbursements. PECO’s outstanding receivable from the DOE for reimbursable costs was $17 million as of December 31, 2012, which has been recorded in other accounts receivable, net on Exelon’s and PECO’s Consolidated Balance Sheets.

On August 15, 2012, PECO suspended installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previously installed meters with an alternative vendor’s meters. PECO intends to move forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment.

Following PECO’s decision, as of October 9, 2012 PECO will no longer use the original smart meters. For the meters that will no longer be used the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period’s earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $19 million, net of approximately $16 million of reimbursements from the DOE. PECO is seeking full recovery of all incurred costs related to the original deployment of meters. For amounts not recovered from the vendor, PECO will seek regulatory rate recovery in a future filing with the PAPUC. PECO did not seek recovery of original meter costs in the January 2013 universal deployment filing, as resolution with the vendor is still pending. In November 2012, PECO requested and received approval from the DOE that the original meters continue to be allowable costs. In addition, PECO remains eligible for the full $200 million in SGIG funds.

As of December 31, 2012, PECO believes the amounts incurred for the original meters and related installation and removal costs are probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As a result, a regulatory asset of $17 million, representing the cost of the original meters, net of accumulated depreciation and DOE reimbursements, was recorded on Exelon’s and PECO’s Consolidated Balance Sheets as of December 31, 2012. If PECO later determines that the regulatory asset is no longer probable of recovery, PECO would be required to recognize a charge in earnings in the period in which that determination was made.

Energy Efficiency Programs (Exelon and PECO). PECO’s PAPUC-approved Phase I EE&C Plan has a four-year term that began on June 1, 2009 and will conclude on May 31, 2013. Spending for Phase I totals more than $328 million pursuant to Act 129’s EE&C reduction targets. The Phase I plan sets forth how PECO will meet the required reduction targets established by Act 129’s EE&C provisions, which include a 3% reduction in electric consumption in PECO’s service territory and a 4.5% reduction in PECO’s annual system peak demand in the 100 hours of highest demand by May 31, 2013. If PECO fails to achieve the required reductions in consumption within the stated deadline, PECO will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers.

244

Combined Notes to Consolidated Financial Statements—(Continued)

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

The peak demand period ended on September 30, 2012 and PECO will report its compliance with the reduction targets in a preliminary filing with the PAPUC on March 1, 2013. The final compliance report is due to the PAPUC by November 15, 2013.

On August 2, 2012, the PAPUC issued its Phase II EE&C implementation order. The order provides energy consumption reduction requirements for the second phase of Act 129’s EE&C programs, which will go into effect on June 1, 2013, but defers a decision on peak demand reduction requirements until 2013. The order tentatively established PECO’s three-year cumulative consumption reduction target at 2.9%. In August 2012, PECO requested an evidentiary hearing regarding the appropriateness of its 2.9% target. The target was subsequently reaffirmed by the PAPUC on December 5, 2012. In addition, on September 4, 2012, PECO filed a Petition for Reconsideration of the terms of the PAPUC’s implementation order for Phase II, which was subsequently denied.

Pursuant to the Phase II implementation order, PECO filed its three-year EE&C Phase II plan with the PAPUC on November 1, 2012. The plan sets forth how PECO will reduce electric consumption by at least 2.9% in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads. The implementation order permits PECO to apply any excess savings achieved during Phase I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the total consumption reductions must be through programs directed toward PECO’s public and low income sectors, respectively. If PECO fails to achieve the required reductions in consumption, it 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 the plan may not exceed 2% of the electric company’s total annual revenue as of December 31, 2006.

Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandated that beginning in 2011, following the expiration of PECO’s rate cap transition period, certain percentages of electric energy sold 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 ranges from approximately 3.5% to 8% and the requirement for Tier II alternative energy resources ranges from 6.2% to 10%. The required compliance percentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129 and the AEPS Act.

PECO has entered into five-year and ten-year agreements with accepted bidders, including Generation, totaling 452,000 non-solar and 8,000 solar Tier I AECs annually in accordance with a PAPUC approved plan. The plan allowed PECO to bank AECs procured prior to 2011 and use the banked AECs to meet its AEPS Act obligations over two compliance years ending May 2013. The PAPUC also approved the procurement of Tier II AECs and supplemental AECs as well as the sale of excess AECs through independent third party auctions or brokers. On January 5, 2012, PECO successfully conducted a competitive procurement for 275,000 Tier II AECs to be available toward its AEPS Act obligations for its compliance years ended May 2012 and ending May 2013, which was approved by the PAPUC on January 17, 2012.

All AEPS administrative costs and costs of AECs incurred after December 31, 2010 are being recovered on a full and current basis from default service customers through a surcharge.

PECO’s second DSP Program eliminated the AEPS rider. Beginning in June 2013, AEPS compliance costs will be recovered through the GSA.

245

Combined Notes to Consolidated Financial Statements—(Continued)

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

Natural Gas Choice Supplier Tariff (Exelon and PECO). During 2011, the PAPUC approved PECO’s tariff supplements to its Gas Choice Supplier Coordination Tariff and its Retail Gas Service Tariff to address the new licensing requirements for natural gas suppliers (NGS) set forth in the PAPUC’s final rulemaking order, which became effective January 1, 2011. The new licensing requirements broaden the types of collateral that PECO can require to mitigate its risk related to an NGS default, as well as PECO’s ability to adjust collateral when material changes in supplier creditworthiness occur. PECO has completed its creditworthiness determinations and notified affected NGSs of their new collateral levels. As a result, PECO has obtained $14 million of collateral as of December 31, 2012.

Investigation of Pennsylvania Retail Electricity Market (Exelon and PECO). On July 28, 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania’s retail electric market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. On March 1, 2012, the PAPUC issued the final order describing more detailed recommendations to be implemented prior to the expiration of the electric distribution company’s current default service plan and providing guidelines for electric distribution companies for development of their next default service plan. On October 12, 2012, the PAPUC approved PECO’s second DSP Program, which includes several new programs to continue PECO’s support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. Further, the PAPUC issued a final order on February 14, 2013, outlining its proposed end-state for default service, which included default service pricing for residential and small commercial customers based on three month full requirements contracts, full requirement contracts using hourly spot market pricing for large commercial and industrial default service customers, and the inclusion of CAP customers in the customer choice programs.

Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC’s authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service during the first year rates are in effect. On August 2, 2012, the PAPUC issued a final order establishing rules and procedures to implement the ratemaking provisions of Act 11. The implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) which outlines how the utility is planning to increase its investment for repairing, improving, or replacing aging infrastructure, approved by the Commission prior to implementing a DSIC. PECO filed its LTIIP for its Gas Operations on February 8, 2013 with the PAPUC.

Maryland Regulatory Matters

2011 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets.

246

Combined Notes to Consolidated Financial Statements—(Continued)

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

These costs are being recovered over a 5-year period that began in December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. The regulatory asset for the storm costs earns a regulated rate of return.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. Additionally, the MDPSC has determined that the cost recovery for the non-AMI meters that BGE retires will be considered in a future depreciation proceeding. The MDPSC continues to evaluate the impacts of a customer opt-out feature in BGE’s Smart Grid program. The ultimate resolution related to this feature could affect BGE’s ability to demonstrate cost-effectiveness of the advanced metering system. Under a grant from the DOE, BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives, which substantially reduces the total cost of these initiatives. The project to install the smart meters began in late April 2012.

As of December 31, 2012, BGE had received $142 million in reimbursements from the DOE. As of December 31, 2012, BGE’s outstanding receivable from the DOE for reimbursable costs was $15 million, which has been recorded in other accounts receivable, net on Exelon’s and BGE’s Consolidated Balance Sheets.

New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that it projected will be in commercial operation by June 1, 2015. The initial term of the proposed contract is 20 years. The CfD mandates that the utilities pay (or receive) the difference between CPV’s contract prices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. The three Maryland utilities are required to enter into a CfD in amounts proportionate to their relative SOS load as of the date of execution. Depending on the precise terms of the CfD, the eventual market conditions, and the manner of cost recovery, the CfD could have a material adverse impact on Exelon’s and BGE’s results of operations, cash flows and financial positions. On April 27, 2012, a civil complaint was filed in the United States District Court for the District of Maryland by certain unaffiliated parties that challenges the actions taken by the MDPSC on federal law grounds. Among other requests for relief, the plaintiffs seek to enjoin the MDPSC from executing or otherwise putting into effect any part of its order. The MDPSC and CPV filed motions to dismiss the federal lawsuit, which were both denied by the U.S. District Court on August 3, 2012. On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order. That petition was subsequently transferred to the Circuit Court for Baltimore City, where similar appeals have been filed by other interested parties. All cases have now been consolidated and will be heard together by the Circuit Court for Baltimore City in the first quarter of 2013.

2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October 22, 2012, BGE filed an updated application to request an increase of $131 million and $45 million to its electric and gas base rates, respectively. The new electric and gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

247

Combined Notes to Consolidated Financial Statements—(Continued)

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

Dividend Restrictions (Exelon and BGE). BGE pays dividends on its common stock after its Board of Directors declares them. However, BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd and BGE). ComEd’s and BGE’s transmission rates are each established based on a FERC-approved formula.

ComEd’s most recent annual formula rate update filed in May 2012 reflects actual 2011 expenses and investments plus forecasted 2012 capital additions. The update resulted in a revenue requirement of $450 million offset by a $5 million reduction related to the reconciliation of 2011 actual costs for a net revenue requirement of $445 million. This compares to the May 2011 updated revenue requirement of $438 million offset by a $16 million reduction related to the reconciliation of 2010 actual costs for a net revenue requirement of $422 million. The increase in the revenue requirement was primarily driven by higher depreciation, pension and operating and maintenance costs, and the absence of a one-time credit that had been included in 2010 costs. The 2012 net revenue requirement became effective June 1, 2012, and is recovered over the period extending through May 31, 2013. The regulatory liability associated with the true-up is being amortized as the associated amounts are refunded.

ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.91%, a decrease from the 9.10% return previously authorized. The decrease in return was primarily due to lower interest rates on ComEd’s long-term debt outstanding. 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 55%.

BGE’s most recent annual formula rate update, filed in April 2012, reflects actual 2011 expenses and investments plus forecasted 2012 capital additions on a weighted basis. This update resulted in a revenue requirement of $156 million plus an additional $2 million increase related to the reconciliation of 2011 actual costs for a net revenue requirement of $158 million. This compares to the May 2011 updated net revenue requirement of $140 million. The increase in the revenue requirement is primarily driven by higher levels of capital investment and operating expenses. The 2012 net revenue requirement became effective June 1, 2012, and is recovered over the period extending through May 31, 2013. The regulatory asset associated with the 2011 revenue requirement true-up is being amortized as the associated amounts are collected from customers.

BGE’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.43%, a decrease from the 8.96% return included in the update filed in April 2011. The decrease in return is primarily due to a reduced equity ratio and cost of debt at 2011 year-end compared to the previous year-end. BGE’s formula rate includes an 11.3% rate of return on common equity for most investments included in its rate base.

248

Combined Notes to Consolidated Financial Statements—(Continued)

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

PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE 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. 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, that 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 January 21, 2010, FERC issued an order establishing paper hearing procedures to supplement the record. On March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order. A number of entities have filed requests for rehearing. 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 anticipates that all impacts of any rate design changes should be recoverable through the transmission service charge rider approved in PECO’s 2010 electric distribution rate case settlement and, thus, the rate design changes are not expected to have a material impact on PECO’s results of operations, cash flows or financial position. To the extent any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO’s results of operations. BGE anticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE’s results of operations, cash flows or financial position.

On October 11, 2012, the PJM Transmission Owners filed with FERC a cost allocation for new transmission facilities asking that the new cost allocation methodology apply to all transmission approved by the PJM Board on or after February 1, 2013. The proposed methodology is a hybrid methodology that would socialize 50% of the costs of new facilities at 500kV and above and double-circuit 345kV lines, and allocate the remaining 50% to direct beneficiaries. For all other facilities, the costs would be allocated to the direct beneficiaries. On January 31, 2013, FERC issued an order stating that the transmission owner filing is interdependent with PJM’s October 25, 2012 Order No. 1000 filing and thus, while FERC accepted the cost allocation for filing, it did so subject to refund, and a further order at the time FERC issues an order on PJM’s Order No. 1000 Compliance Filing.

ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE’s estimated commitments are as follows:


	Total		2013		2014		2015		2016		2017
ComEd	$	525	$	175	$	86	$	135	$	128	$	1
PECO		140		28		23		26		36		27
BGE		249		15		53		119		55		7

249

Combined Notes to Consolidated Financial Statements—(Continued)

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

PJM Minimum Offer Price Rule (Exelon and Generation). PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The proceedings leading to the FERC’s approval of the existing MOPR were extensive. The parties disputed numerous elements of the MOPR including: (i) the default price that should apply to bids found subject to the MOPR, (ii) the duration of the MOPR and (iii) the application of the MOPR to self-supplying capacity and state-sponsored capacity. The FERC orders approving the existing MOPR have been appealed to the Third Circuit Court of Appeals. A resolution of that appeal is not expected until sometime in 2013.

In May 2012, PJM announced the results of its capacity auction covering 2015 and 2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. Potentially, states will expand such state-sanctioned subsidy programs or other states may seek to establish similar programs. Generation believes that further revisions to the MOPR are necessary to ensure that the potential to reduce artificially capacity auction prices is appropriately limited in PJM. In late December 2012, PJM filed a new MOPR for approval at the FERC, which Exelon believes will be more effective in preventing state-sanctioned subsidy contracts from artificially reducing capacity prices. Generation was actively involved in the process through which the MOPR changes were developed, supports the changes and intends to continue to work with PJM and its stakeholders to obtain necessary approvals. On February 5, 2013, the FERC issued a letter finding that PJM’s new MOPR filing is deficient and requested that PJM provide additional information on several aspects of PJM’s MOPR proposal. PJM has 30 days to respond, and a FERC decision is expected within 60 days thereafter.

Market-Based Rates (Exelon, Generation, ComEd, PECO and BGE). Generation, ComEd, PECO and BGE 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, PECO and BGE 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, PECO or BGE has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds in certain instances if it finds that the market-based rates are not just and reasonable under the Federal Power Act.

As required by FERC’s regulations, as promulgated in the Order No. 697 series, Generation, ComEd, PECO and BGE have filed market power analyses using the prescribed market share screens to demonstrate that Generation, ComEd, PECO and BGE qualify for market-based rates in the regions where they are selling energy and capacity under market-based rate tariffs. FERC accepted the 2008 filings on September 16, 2008, January 15, 2009 and September 2, 2009 and accepted the 2009 filings on July 28, 2009, October 26, 2009, February 23, 2010 and April 30, 2010, affirming Exelon’s affiliates continued right to make sales at market-based rates. These analyses must examine historic test period data and must be updated every three years on a prescribed schedule. The most recent updated analysis for the PJM and Northeast Regions was filed in late 2010, based on 2009 historic test period data. On June 22, 2011, FERC issued an order confirming Generation’s continued authority to charge market based rates, based on Generation’s most recent updated analysis filed in 2010, stating that any market power concerns are adequately addressed by PJM’s monitoring and mitigation programs. Similarly, on June 29, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the Central Region which the FERC accepted on November 13, 2012, and on December 23, 2011, Generation filed its updated market power analysis for the Southeast Region which the FERC accepted on October 10, 2012. On December 21, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the SPP region, and the FERC has not yet acted on this filing.

250

Combined Notes to Consolidated Financial Statements—(Continued)

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

Reliability Pricing Model (Exelon, Generation and BGE). PJM’s RPM auctions take place 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2016 occurred in May 2012.

License Renewals (Exelon and Generation). On April 8, 2009, the NRC issued a renewed operating license for Oyster Creek that expires in April 2029. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019.

On June 30, 2011, the NRC issued the renewed operating licenses for Salem Units 1 and 2 expiring in 2036 and 2040, respectively. Exelon is a 42.59% owner of the Salem Units.

On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States District Court of Appeals for the DC Circuit vacated the NRC’s temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court’s decision is addressed. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule through rulemaking no later than September 6, 2014. Generation does not expect the NRC to issue license renewals until September 2014, at the earliest.

On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project and the Muddy Run Pumped Storage Facility Project, respectively. The FERC review process is expected to be completed by August 31, 2014, when the current Conowingo license expires.

251

Combined Notes to Consolidated Financial Statements—(Continued)

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

Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)

Exelon, ComEd, PECO and BGE prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2012 and 2011. Upon consummation of the merger, the Registrants reclassified certain regulatory asset and liability balances as of December 31, 2011 in order to align the reporting of the regulated utilities.


December 31, 2012	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	304	$	3,673	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes		14		1,382		5		62		—		1,255		9		65
AMI programs		3		70		3		10		—		29		—		31
AMI meter events		—		17		—		—		—		17		—		—
Under-recovered distribution service costs		18		191		18		191		—		—		—		—
Debt costs		14		68		11		62		3		6		1		9
Fair value of BGE long-term debt ^(a)		—		256		—		—		—		—		—		—
Fair value of BGE supply contract ^(b)		77		12		—		—		—		—		—		—
Severance		29		28		25		12		—		—		4		16
Asset retirement obligations		—		90		—		65		—		25		—		—
MGP remediation costs		58		232		51		197		6		33		1		2
RTO start-up costs		3		2		3		2		—		—		—		—
Under-recovered electric universal service fund costs		11		—		—		—		11		—		—		—
Financial swap with Generation		—		—		226		—		—		—		—		—
Renewable energy and associated RECs		18		49		18		49		—		—		—		—
Under-recovered energy and transmission costs		43		—		14		—		1		—		28		—
DSP Program costs		1		3		—		—		1		3		—		—
DSP II Program costs		1		2		—		—		1		2		—		—
Deferred storm costs		3		6		—		—		—		—		3		6
Electric generation-related regulatory asset		16		40		—		—		—		—		16		40
Rate stabilization deferral		67		225		—		—		—		—		67		225
Energy efficiency and demand response programs		56		126		—		—		—		—		56		126
Other		23		25		14		16		9		8		—		2

Total regulatory assets	$	759		6,497	$	388	$	666	$	32	$	1,378	$	185	$	522

(a)	Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. See Note 4—Merger and Acquisitions for additional information.

(b)

Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE’s supply contracts as of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved regulated rates. See Note 4—Merger and Acquisitions for additional information.

252

Combined Notes to Consolidated Financial Statements—(Continued)

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


December 31, 2012	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory liabilities
Nuclear decommissioning	$	—	$	2,397	$	—	$	2,037	$	—	$	360	$	—	$	—
Removal costs		97		1,406		75		1,192		—		—		22		214
Energy efficiency and demand response programs		131		—		43		—		88		—		—		—
Electric distribution tax repairs		20		132		—		—		20		132		—		—
Gas distribution tax repairs		8		46						8		46
Over-recovered uncollectible accounts		6		—		6		—		—		—		—		—
Over-recovered energy and transmission costs		54		—		6		—		48		—		—		—
Over-recovered gas universal service fund costs		3		—		—		—		3		—		—		—
Over-recovered AEPS costs		2		—		—		—		2		—		—		—

Total regulatory liabilities	$	321	$	3,981	$	130	$	3,229	$	169	$	538	$	22	$	214


December 31, 2011	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	204	$	2,794	$	—	$	—	$	7	$	—	$	3	$	—
Deferred income taxes		5		1,176		5		66		—		1,110		8		68
AMI and smart meter programs		2		28		2		6		—		22		—		15
Under-recovered distribution service costs		14		70		14		70		—		—		—		—
Debt costs		18		81		15		73		3		8		2		10
Severance		25		38		25		38		—		—		—		1
Asset retirement obligations		—		74		—		50		—		24		—		—
MGP remediation costs		30		129		24		91		6		38		1		2
RTO start-up costs		3		4		3		4		—		—		—		—
Under-recovered electric universal service fund costs		3		—		—		—		3		—		—		—
Financial swap with Generation		—		—		503		191		—		—		—		—
Renewable energy and associated RECs		9		97		9		97		—		—		—		—
Under-recovered energy and transmission costs		57		—		48		—		9		—		50		—
DSP Program costs		3		2		—		—		3		2		—		—
Deferred storm costs		—		—		—		—		—		—		3		9
Electric generation-related regulatory asset		—		—		—		—		—		—		16		56
Rate stabilization deferral		—		—		—		—		—		—		63		295
Energy efficiency and demand response programs		—		—		—		—		—		—		29		95
Other		17		25		9		13		8		12		—		—

Total regulatory assets	$	390	$	4,518	$	657	$	699	$	39	$	1,216	$	175	$	551

253

Combined Notes to Consolidated Financial Statements—(Continued)

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


December 31, 2011	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory liabilities
Nuclear decommissioning	$	—	$	2,222	$	—	$	1,857	$	—	$	365	$	—	$	—
Removal costs		61		1,185		61		1,185		—		—		18		200
Energy efficiency and demand response programs		49		69		49		—		—		69		—		—
Electric distribution tax repairs		19		151		—		—		19		151		—		—
Over-recovered uncollectible accounts		15		—		15		—		—		—		—		—
Over-recovered energy and transmission costs		42		—		12		—		30		—		—		—
Over-recovered gas universal service fund costs		3		—		—		—		3		—		—		—
Over-recovered AEPS costs		8		—		—		—		8		—		—		—
Other		—		—		—		—		—		—		1		1

Total regulatory liabilities	$	197	$	3,627	$	137	$	3,042	$	60	$	585	$	19	$	201

Pension and other postretirement benefits. As of December 31, 2012, Exelon recorded regulatory assets of $3,977 million related to ComEd’s and BGE’s portion of deferred costs associated with Exelon’s pension plans and ComEd’s, PECO’s and BGE’s portion of deferred costs associated with Exelon’s other postretirement benefit plans. PECO’s pension regulatory recovery is based on cash contributions and is not included in the regulatory asset balance. The regulatory asset is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses attributable to Exelon’s pension and other postretirement benefit plans determined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. ComEd, PECO and BGE will recover these costs through base rates as allowed in their most recently approved regulated rate orders. The pension and other postretirement benefit regulatory asset balance includes a regulatory asset established at the date of the merger related to BGE’s portion of the deferred costs associated with legacy Constellation’s pension and other postretirement benefit plans. That BGE-related regulatory asset is being amortized over a period of approximately 12 years, which generally represents the expected average remaining service period of plan participants at the date of the merger. See Note 14—Retirement Benefits for additional detail. No return is earned on Exelon’s regulatory asset.

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 under GAAP. 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, PAPUC and MDPSC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future transmission and distribution rates. For ComEd and BGE, this amount includes the impacts of a reduction in the deductibility, for Federal income tax purposes, of certain retiree health care costs pursuant to the March 2010 Health Care Reform Acts. ComEd was granted recovery of these additional income taxes on May 24, 2011 in the ICC’s 2010 Rate Case order. The recovery period for these costs is through May 31, 2014. For BGE, these additional income taxes are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. See Note 12—Income Taxes and Note 14—Retirement Benefits for additional information. ComEd, PECO and BGE are not earning a return on the regulatory asset in base rates.

254

Combined Notes to Consolidated Financial Statements—(Continued)

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

AMI programs. For ComEd, this amount represents operating and maintenance expenses and meter costs associated with ComEd’s AMI pilot program approved in the May 24, 2011, ICC order in ComEd’s 2010 rate case. The recovery periods for operating and maintenance expenses and meter costs are through May 31, 2014, and January 1, 2020, respectively. In addition, ComEd recorded approximately $7 million of accelerated depreciation costs resulting from the early retirements of non-AMI meters as a regulatory asset beginning during the fourth quarter of 2012, which will be amortized over an average ten year period pursuant to the ICC approved AMI Deployment plan. ComEd is earning a return on the meter costs. For PECO, this amount represents accelerated depreciation and filing and implementation costs relating to the PAPUC-approved Smart Meter Procurement and Installation Plan as well as the return on the un-depreciated investment, taxes, and operating and maintenance expenses. The approved plan allows for recovery of filing and implementation costs incurred through December 31, 2010 during 2011 and 2012. In addition, the approved plan provides for recovery of program costs, which includes depreciation on new equipment placed in service, beginning in January 2011 on full and current basis, which includes interest income or expense on the under or over recovery. The approved plan also provides for recovery of accelerated depreciation on PECO’s non-AMI meter assets over a 10-year period ending December 31, 2020. For BGE, this amount represents smart grid pilot program costs as well as the incremental costs associated with implementing full deployment of a smart grid program. Pursuant to a MDPSC order, pilot program costs of $11 million were deferred in a regulatory asset, and, beginning with the MDPSC’s March 2011 rate order, is earning BGE’s most current authorized rate of return. In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE, authorizing BGE to establish a separate regulatory asset for incremental costs incurred to implement the initiative, including the net depreciation and amortization costs associated with the meters, and an authorized rate of return on these costs, a portion of which is not recognized under GAAP until cost recovery begins. Additionally, the MDPSC order requires that BGE prove the cost-effectiveness of the entire smart grid initiative prior to seeking recovery of the costs deferred in these regulatory assets. Therefore, the commencement and timing of the amortization of these deferred costs is currently unknown. BGE’s AMI regulatory asset excludes costs for non-AMI meters being replaced by AMI meters, as the MDPSC has ordered that the cost recovery for non-AMI meters will be considered in a future depreciation proceeding.

AMI Meter Events. This amount represents the cost value of the original smart meters, net of accumulated depreciation and DOE reimbursements, purchased for the first phase of smart meter deployment that will no longer be used, including installation and removal costs. PECO is seeking full recovery of all incurred costs related to the original deployment of meters. For amounts not recovered from the vendor, PECO will seek regulatory rate recovery in a future filing with the PAPUC. PECO believes the amounts incurred for the original meters and related installation and removal costs are probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As such, PECO has deferred these costs on Exelon’s and PECO’s Consolidated Balance Sheet. PECO will not earn a return on the recovery of these costs.

Under-recovered distribution services costs. Under EIMA, which became effective in the fourth quarter of 2011, ComEd is allowed recovery of distribution services costs through a formula rate tariff. The legislation provides for an annual reconciliation of the revenue requirement in effect to reflect the actual costs that the ICC determines are prudently and reasonably incurred in a given year. The reconciliation will be recovered through rates over a one-year period, beginning in January 2013 for the 2011 annual reconciliation period. The regulatory asset also includes costs associated with certain one-time events, such as large storms, which will be recovered over a five-year period beginning in January 2013. ComEd is earning a return on these costs. As of December 31, 2012, the regulatory asset was comprised of $125 million for the annual reconciliation and $84 million related to significant

255

Combined Notes to Consolidated Financial Statements—(Continued)

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

one-time events. In addition to $58 million in deferred storm costs, net of amortization, the December 31, 2012 balance related to significant one-time events contains $26 million of merger and integration related costs, net of amortization, incurred as a result of the merger. As of December 31, 2012, ComEd and BGE recorded regulatory assets of $5 million and $1 million, respectively, in other regulatory assets for merger and integration-related costs. See Note 4—Mergers and Acquisitions for additional information.

Debt costs. Consistent with rate recovery for ratemaking purposes, ComEd’s, PECO’s and BGE’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. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding or the life of the original issuance retired. These debt costs are used in the determination of the weighted cost of capital applied to rate base in the rate-making process. ComEd and BGE are not earning a return on the recovery of these costs.

Severance. For ComEd, these costs represent previously incurred severance costs that ComEd was granted recovery of in the December 20, 2006, ICC rehearing rate order and the May 24, 2011, ICC order in ComEd’s 2010 rate case. The recovery periods are through June 30, 2014, and May 31, 2014, respectively. ComEd is not earning a return on these costs. For BGE, these costs represent deferred severance costs that BGE has either previously been granted recovery of in rates or has requested recovery in a current rate case. Costs include the portion of costs associated with a 2008 workforce reduction that relate to BGE’s gas business which were deferred in 2009 as a regulatory asset in accordance with the MDPSC’s orders in prior rate cases and are being amortized over a 5-year period that began in January 2009. Also included are costs associated with a 2010 workforce reduction that were deferred as a regulatory asset and are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. Finally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance with the MDPSC’s orders in prior rate cases and are being amortized over a 5-year period that began in July 2012. BGE is earning a regulated return on the regulatory asset included in base rates.

Asset retirement obligations. These costs represent future removal costs associated with ComEd’s and PECO’s existing asset retirement obligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd will recover these costs through future depreciation expense and will earn a return on these costs once the removal activities have been performed. See Note 13—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 are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures. ComEd and PECO are not earning a return on the recovery of these costs. For BGE, $5 million of clean-up costs incurred during the period from July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates in accordance with MDPSC orders. These costs are being amortized over 10-year periods that began in January 2006 and December 2010, respectively. BGE is earning a regulated return on the regulatory asset included in base rates. See Note 19—Commitments and Contingencies for additional information.

256

Combined Notes to Consolidated Financial Statements—(Continued)

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

RTO start-up costs. Recovery of these RTO start-up costs was approved by FERC. The recovery period is through March 31, 2015. ComEd is earning a return on these costs.

Under (Over)-recovered universal service fund costs. The universal service fund cost is a recovery mechanism that allows PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of December 31, 2012, PECO was under-recovered for its electric program and over-recovered for its gas program. PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers.

Financial swap with Generation. To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap contract with Generation that expires on May 31, 2013. 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 does not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position is based on the difference between 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.

Renewable Energy and Associated RECs. On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Since the swap contracts were deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period as well as an offsetting regulatory asset or liability are recorded by ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position is based on the difference between ComEd’s cost to purchase energy on the spot market and the contracted price.

Under (Over)-recovered energy and transmission costs. Starting in 2007, ComEd’s energy and transmission costs are recoverable (refundable) under ComEd’s ICC and/or FERC-approved rates. ComEd earns interest on under-recovered costs and pays interest on over-recovered costs to customers. The PECO energy costs represent the electric and gas supply related costs recoverable (refundable) under PECO’s GSA and PGC, respectively. PECO earns interest on the under-recovered energy and natural gas costs and pays interest on over-recovered energy and natural gas costs to customers. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSC under which PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2012, PECO had a regulatory asset related to under-recovered electric transmission costs of $1 million and a regulatory liability that included $47 million related to over-recovered electric supply costs under the GSA and $1 million related to over-recovered natural gas supply costs under the PGC. As of December 31, 2011, PECO had a regulatory asset related to under-recovered transmission costs of $9 million and a regulatory liability that included $25 million related to over-recovered electric supply costs under the GSA and $5 million related to over-recovered natural gas supply costs under the PGC. The BGE energy costs represent the electric and gas supply related costs recoverable (refundable) from (to) customers under BGE’s market-based SOS and MBR programs, respectively. BGE does not earn or pay interest on under- or over-recovered costs to customers. See “ITEM 1. BUSINESS—BGE” for further details on BGE’s market-based SOS and MBR programs. As of December 31, 2012, BGE had a regulatory asset that included $9 million related to under-recovered electric supply costs and $19 million related to under-recovered natural gas supply costs.

257

Combined Notes to Consolidated Financial Statements—(Continued)

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

DSP Program costs. These amounts represent recoverable administrative costs incurred relating to filing, procurement, and information technology improvements associated with PECO’s PAPUC-approved DSP Program for the procurement of electric supply following the expiration of PECO’s generation rate caps on December 31, 2010. The filing and implementation costs of this DSP Program are recoverable through the GSA over its 29-month term, beginning January 1, 2011. The independent evaluator costs associated with conducting procurements is recoverable over a 12-month period after the PAPUC approves the results of the procurements. Costs relating to information technology improvements are recoverable over a 5-year period beginning January 1, 2011. PECO earns a return on the recovery of information technology costs.

DSP II Program Costs. These amounts represent recoverable administrative costs incurred relating to the filing and procurement associated with PECO’s second PAPUC-approved DSP program for the procurement of electric supply. The filing and procurement of this DSP Program are recoverable through the GSA over its 24-month term, beginning June 1, 2013. The independent evaluator costs associated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results of the procurements. PECO is not earning a return on these costs.

Deferred storm costs. In the MDPSC’s March 2011 rate order, BGE was authorized to defer $16 million in storm costs incurred in February 2010. These costs are being amortized over a 5-year period that began in December 2010. BGE is earning a regulated return on the regulatory asset included in base rates.

Electric generation-related regulatory asset. As a result of the deregulation of electric generation, BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual, generation-related regulatory assets and liabilities and established a single, generation-related regulatory asset to be collected through its regulated rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. A portion of this regulatory asset represents income taxes recoverable through future rates that do not earn a regulated rate of return. These amounts were $47 million as of December 31, 2012, and $56 million as of December 31, 2011. BGE will continue to amortize this amount through 2017.

Rate stabilization deferral. In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006, to May 31, 2007. In addition, as required by Senate Bill 1, the MDPSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007, to January 1, 2008. During 2007, BGE deferred $306 million of electricity purchased for resale expenses and certain applicable carrying charges, which are calculated using the implied interest rates of the rate stabilization bonds, as a regulatory asset related to the rate stabilization plans. During 2012 and 2011, BGE recovered $67 million and $57 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007.

Energy efficiency and demand response programs. These amounts represent costs recoverable (refundable) under ComEd’s ICC approved Energy Efficiency and Demand Response

258

Combined Notes to Consolidated Financial Statements—(Continued)

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

Plan, PECO’s PAPUC-approved EE&C Plan, and BGE’s Smart Energy Savers Program^®. ComEd began recovering these costs or refunding over-collections of these costs on June 1, 2008 through a rider. ComEd earns a return on the capital investment incurred under the program but does not earn (pay) interest on under (over) collections. PECO began recovering these costs through a rider in January 2010 based on projected spending under the program. Recovery will continue over the life of the program, which expires on May 31, 2013. Excess funds collected are required to be refunded no later than June 30, 2013. PECO earns a return on the capital investment incurred under the program but does not earn (pay) interest on under (over) collections. BGE’s Smart Energy Savers Program^® includes both MDPSC approved demand response and energy efficiency programs. For the BGE demand response program which began in January 2008, actual marketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of the equipment. Actual costs incurred in the conservation program are being amortized over a 5- year period with recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a regulated rate of return on the capital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections.

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, September 10, 2008, and May 24, 2011. The recovery period for the two former rate case costs was through September 15, 2011. The recovery period for the 2010 Rate Case costs is through May 31, 2014. Pursuant to the approved settlements of the 2010 electric and natural gas distribution rate cases, PECO is allowed recovery of rate case costs over two years ended December 31, 2012. ComEd and PECO do not earn a return on the recovery of these costs.

Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 13—Asset Retirement Obligations for additional information.

Removal costs. These amounts represent funds ComEd and BGE have received from customers to cover the future removal of property, plant and equipment which reduces rate base for ratemaking purposes.

Electric distribution tax repairs. PECO’s 2010 electric distribution rate case settlement required that the expected cash benefit from the application of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-year period. Credits began being reflected in customer bills on January 1, 2012. No interest will be paid to customers.

Gas distribution tax repairs. PECO’s 2010 natural gas distribution rate case settlement required that the expected cash benefit from the application of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. Credits will be reflected in customer bills beginning January 1, 2013. No interest will be paid to customers.

259

Combined Notes to Consolidated Financial Statements—(Continued)

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

Under (Over)-recovered uncollectible accounts. As a result of the February 2010 ICC order approving recovery of ComEd’s uncollectible accounts, ComEd has the ability to adjust its rates annually to reflect the increases and decreases in annual uncollectible accounts expense starting with year 2008. ComEd recorded a regulatory asset for the cumulative under-collections in 2008 and 2009. Recovery of the initial regulatory asset was completed over an approximate 14-month time frame which began in April 2010. The recovery or refund of the difference in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. ComEd is not earning a return on these costs.

Under (Over)-recovered AEPS costs current asset (liability). The AEPS costs represent the administrative and AEC costs incurred to comply with the requirements of the AEPS Act, which are recoverable on a full and current basis. PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers.

Purchase of Receivables Programs (Exelon, ComEd, PECO, and BGE)

ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers. For retail suppliers participating in the utilities’ consolidated billing, ComEd, PECO and BGE must purchase their customer accounts receivables. ComEd and BGE purchase receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO, and BGE do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are classified in other accounts receivable, net on Exelon’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of December 31, 2012 and 2011.


As of December 31, 2012	Exelon			ComEd			PECO			BGE
Purchased receivables ^(a)	$	191		$	55		$	65		$	71
Allowance for uncollectible accounts ^(b)		(21	)		(9	)		(6	)		(6	)

Purchased receivables, net	$	170		$	46		$	59		$	65


As of December 31, 2011	Exelon			ComEd			PECO			BGE
Purchased receivables ^(a)	$	68		$	16		$	52		$	61
Allowance for uncollectible accounts ^(b)		(5	)		—			(5	)		(3	)

Purchased receivables, net	$	63		$	16		$	47		$	58

(a)

PECO’s gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.

(b)	For ComEd, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.

260

Combined Notes to Consolidated Financial Statements—(Continued)

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

4. Merger and Acquisitions

Merger with Constellation (Exelon, Generation, ComEd, PECO and BGE)

Description of Transaction

On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement, among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’s interest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon’s interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including those with generation and customer supply operations that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger.

Constellation’s shareholders received 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock outstanding as of March 12, 2012. Generally, all outstanding Constellation equity-based compensation awards were converted into Exelon equity-based compensation awards using the same ratio. See Note 17—Common Stock for further information.

Regulatory Matters

In December 2011, Exelon and Constellation reached a settlement with the State of Maryland and the City of Baltimore and other interested parties in connection with the regulatory proceedings related to the merger that were pending before the MDPSC. As part of this settlement and the application for approval of the merger by MDPSC, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of more than $1 billion.

261

Combined Notes to Consolidated Financial Statements—(Continued)

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

On February 17, 2012, the MDPSC approved the merger with conditions. Many of the conditions were reflective of the settlement agreements described above. The following costs were recognized after the closing of the merger and are included in Exelon’s, Generation’s and BGE’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012:


Description	Payment Period	BGE			Generation		Exelon			Statement of Operations Location
BGE rate credit of $100 per residential customer ^(a)	Q2 2012	$	113		$	—	$	113		Revenues
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers	2012 to 2014		—			—		113.5		O&M Expense
Contribution for renewable energy, energy efficiency or related projects in Baltimore	2012 to 2014		—			—		2		O&M Expense
Charitable contributions at $7 million per year for 10 years	2012 to 2021		28			35		70		O&M Expense
State funding for offshore wind development projects	Q2 2012		—			—		32		O&M Expense
Miscellaneous tax benefits	Q2 2012		(2	)		—		(2	)	Taxes Other Than Income

Total		$	139		$	35	$	328.5

(a)	Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.

In addition to these costs, the direct investment estimate includes $95 million to $120 million for the requirement to cause construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. The construction is expected to be completed in 1 to 2 years. The estimate also includes $625 million for Exelon’s and Generation’s commitment to develop or assist in the development of 285—300 MWs of new generation in Maryland, expected to be completed over a period of 10 years. Such costs, which are expected to be primarily capital in nature, will be recognized as incurred. As of December 31, 2012, amounts reflected in the Exelon and Generation consolidated financial statements for these commitments were immaterial.

The settlement agreement contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets, and therefore will be primarily capital in nature and recognized as incurred. If in the future Exelon determines that it is probable that it will make subsidy, compliance or liquidated damages payments related to the new generation development commitments, Exelon will record a liability at that time. As of December 31, 2012, it is reasonably possible that Exelon will be required to make subsidy or liquidated damages payments of approximately $40 million rather than build one of the generation projects contemplated by the commitments, given that the generation build is dependent upon the passage of legislation and other conditions that Exelon does not control.

Pursuant to the MDPSC merger approval conditions, BGE is restricted from paying any dividend on its common shares through the end of 2014, is required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and is not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process.

262

Combined Notes to Consolidated Financial Statements—(Continued)

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

Associated with certain of the regulatory approvals required for the merger, Exelon and Constellation agreed to enter into contracts to sell three Constellation generating stations located in PJM within 150 days (subsequently extended 30 days by the DOJ) following the merger completion and to complete the divestitures within 30 days after receipt of regulatory approvals. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland, include base-load, coal-fired generation units plus associated gas/oil units located at the same sites, and total 2,648 MW of generation capacity.

On August 8, 2012, a subsidiary of Generation reached an agreement to sell these three Maryland generating stations and associated assets to Raven Power Holdings LLC (Raven Power), a subsidiary of Riverstone Holdings LLC. The sale was completed on November 30, 2012. The sale agreement included a base price with purchase price adjustments based on fuel inventory, working capital, capital expenditures, and timing of the closing, resulting in net proceeds from the sale of approximately $371 million. Decisions by certain market participants to remove themselves from the bidding process, combined with the deadlines and limitations on the pool of potential buyers imposed by the merger approval orders, resulted in realized sales proceeds below Generation’s estimated fair value of the Maryland generating stations. Consequently, Exelon and Generation recorded a pre-tax loss of $278 million in operating and maintenance expense in the third quarter of 2012 to reflect the difference between the estimated sales price at that time and carrying value. This loss amount was adjusted to $272 million to reflect the final sales price upon closing on November 30, 2012.

In connection with the sale of the Maryland generating stations, Exelon agreed to indemnify Raven Power for certain costs associated with the treatment of hazardous substances at off-site disposal facilities and any claims arising as a result of, or in connection with, any toxic tort, natural resource damages, loss of life or injury to persons due to releases of, or exposure to hazardous substances in connection with Raven Power’s remediation of environmental contamination or Exelon’s non-compliance with environmental laws or permits prior to the closing date of the sale.

Subsequent to the merger, Generation discovered that, for the first two weeks following the merger, due to a software error, Generation inadvertently bid certain generating units into the PJM energy market at prices that slightly exceeded the cost-based caps to which it had agreed. This error was a violation of the commitments made in connection with merger approvals by DOJ, FERC and the MDPSC. Generation reported the error to the DOJ, FERC and the MDPSC and committed to remedy the impacts of its error. The MDPSC held a hearing to review the error, and accepted Generation’s proposed remediation. Subsequent close examination by Generation of its cost-based bids also revealed the need for some minor adjustments to the cost build up for certain of its PJM units. Generation has coordinated with PJM to determine the impact on Generation’s revenues and the market from this error and these adjustments, and Generation has worked with PJM to reverse the financial impacts. In November 2012, Generation reached a settlement with the DOJ regarding this matter. The final resolution did not have a material impact on Exelon’s or Generation’s results of operations, cash flows or financial position.

In addition, in January 2012, Exelon and Constellation reached an agreement with EDF under which EDF withdrew its opposition to the Exelon-Constellation merger. The terms of the agreement address CENG, a joint venture between Constellation and EDF that owns and operates a total of three nuclear facilities with a total of five generating units in Maryland and New York. The agreement reaffirms the terms of the joint venture. The agreement did not include any exchange of monetary consideration, and Exelon does not expect the agreement will have a material effect on Exelon’s and Generation’s future results of operations, financial position and cash flows.

263

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon was named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information was disclosed and sought rescission of the proposed merger. During the third quarter of 2011, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures to Constellation shareholders. On June 26, 2012, the court approved the settlement and entered final judgment.

Accounting for the Merger Transaction

The total consideration in the merger was based on the opening price of a share of Exelon common stock on March 12, 2012 (in millions):


	Number of Shares/ Awards Issued		Total Fair Value
Issuance of Exelon common stock to Constellation shareholders and equity award holders at the exchange ratio of 0.930 shares for each share of Constellation common stock; based on the opening price of Exelon common stock on March 12, 2012 of $38.91 ^(a)		187.45	$	7,294
Issuance of Exelon equity awards to replace existing Constellation equity awards ^(b)		11.30		71

Total purchase price			$	7,365

(a)

The number of shares issued excludes 0.7 million shares of stock that are held in a custodian account specifically for the settlement of unvested share-based restricted stock awards. The related share value is excluded from the estimated fair value as these awards have not vested and, therefore, are not in the purchase price.

(b)	Includes vested Constellation stock options and restricted stock units converted at fair value to Exelon awards on March 12, 2012. The fair value of the stock options was determined using the Black-Scholes model.

All options to purchase Constellation common stock under various equity agreements were converted into options to acquire a number of shares of Exelon common stock (as adjusted for the exchange ratio) at an option price. All Constellation unvested restricted stock awards granted prior to April 28, 2011, that were outstanding immediately prior to the consummation of the Merger, became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to the closing of the Initial Merger) and converted into Exelon common stock at the exchange ratio in accordance with the applicable stock plan and award agreement terms. All Constellation restricted stock awards that remained unvested on a pro rata basis pursuant to the foregoing formula, and any Constellation unvested restricted stock awards granted after April 28, 2011, have been assumed by Exelon and automatically converted into shares of unvested restricted stock of Exelon at the exchange ratio. Likewise, all restricted stock units granted prior to April 28, 2011 under the Constellation Plans and outstanding immediately prior to the completion of the Initial Merger became vested on a pro rata basis (determined based upon the number of months from the start of the applicable restricted period to the closing of the Initial Merger) and have been assumed by Exelon and automatically converted into a number of shares of Exelon common stock at the exchange ratio.

The fair value of Constellation’s non-regulated business assets acquired and liabilities assumed was determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed.

264

Combined Notes to Consolidated Financial Statements—(Continued)

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

The financial statements of BGE do not include fair value adjustments for assets or liabilities subject to rate-setting provisions for BGE. BGE is subject to the rate-setting authority of FERC and the MDPSC and is accounted for pursuant to the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for BGE provide revenue derived from costs including a return on investment of assets and liabilities included in rate base. Except for debt, fuel supply contracts and regulatory assets not earning a return, the fair values of BGE’s tangible and intangible assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, do not reflect any net adjustments related to these amounts. For BGE’s debt, fuel supply contracts and regulatory assets not earning a return, the difference between fair value and book value of BGE’s assets acquired and liabilities assumed is recorded as a regulatory asset at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 1—Significant Accounting Policies for additional information on BGE’s push-down accounting treatment. Also see Note 3 – Regulatory Matters for additional information on BGE’s regulatory assets.

The valuations performed in the first quarter of 2012 to assess the fair values of certain assets acquired and liabilities assumed were considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2012. The allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about the fair value of assets acquired and liabilities assumed. The preliminary valuations performed in the first quarter of 2012 were updated in the second, third and fourth quarters of 2012, with the most significant adjustments to the preliminary valuation amounts having been made to the fair values assigned to the acquired power supply and fuel contracts, unregulated property, plant and equipment and investments in affiliates. The preliminary amounts recognized are subject to further revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the merger date. Any changes to the fair value assessments may affect the purchase price allocation and material changes could require the financial statements to be retroactively amended.

The updated preliminary purchase price allocation of the Initial Merger of Exelon with Constellation and Exelon’s contribution of certain subsidiaries of Constellation to Generation at December 31, 2012 was as follows:


Preliminary Purchase Price Allocation, excluding amortization	Exelon		Generation
Current assets	$	4,936	$	3,638
Property, plant and equipment		9,342		4,054
Unamortized energy contracts		3,218		3,218
Other intangibles, trade name and retail relationships		457		457
Investment in affiliates		1,942		1,942
Pension and OPEB regulatory asset		740		—
Other assets		2,265		1,266

Total assets		22,900		14,575

Current liabilities		3,408		2,804
Unamortized energy contracts		1,722		1,512
Long-term debt, including current maturities		5,632		2,972
Noncontrolling interest		90		90
Deferred credits and other liabilities and preferred securities		4,683		1,933

Total liabilities, preferred securities and noncontrolling interest		15,535		9,311

Total purchase price	$	7,365	$	5,264

265

Combined Notes to Consolidated Financial Statements—(Continued)

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

Intangible Assets Recorded

For the power supply and fuel contracts acquired from Constellation, the difference between the contract price and the market price at the date of the merger was recognized as either an intangible asset or liability based on whether the contracts were in or out-of-the-money. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the merger date. Amortization expense and income are recorded through purchased power and fuel expense or operating revenues. Exelon and Generation present separately in their Consolidated Balance Sheets the unamortized energy contract assets and liabilities for these contracts. Exelon’s and Generation’s amortization expense for the period March 12, 2012 to December 31, 2012 amounted to $1,098 million. This amortization expense excludes the $116 million in amortization of the regulatory asset and equally offsetting amortization of the fuel supply contract liability recorded at Exelon Corporate in the Consolidated Statement of Operations. The weighted-average amortization period is approximately 1.5 years.

The fair value of the Constellation trade name intangible asset was determined based on the relief from royalty method of the income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the hypothetical royalty rate and the discount rate. Exelon’s and Generation’s straight line amortization expense for the period March 12, 2012 to December 31, 2012 amounted to $20 million. The amortization period is approximately 10 years. The trade name intangible asset is included in deferred debits and other assets within Exelon’s and Generation’s Consolidated Balance Sheets.

The fair value of the retail relationships was determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the customer attrition rate and the discount rate. The intangible assets are amortized as amortization expense on a straight line basis over the useful life of the underlying assets averaging approximately 12.4 years. Exelon’s and Generation’s amortization expense for the period March 12, 2012 to December 31, 2012 amounted to $15 million. The retail relationships intangible assets are included in deferred debits and other assets within Exelon’s and Generation’s Consolidated Balance Sheets.

266

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon’s intangible assets and liabilities acquired through the merger with Constellation included in its Consolidated Balance Sheets, along with the future estimated amortization, were as follows as of December 31, 2012:


Description	Weighted Average Amortization		Gross		Accumulated Amortization			Net		Estimated amortization expense
Description	Weighted Average Amortization		Gross		Accumulated Amortization			Net		2013		2014		2015		2016			2017			2018 and Beyond
Unamortized energy contracts, net ^(a)		1.5	$	1,496	$	(982	)	$	514	$	394	$	74	$	19	$	(31	)	$	(22	)	$	80
Trade name		10.0		243		(20	)		223		24		24		24		24			24			103
Retail relationships		12.4		214		(15	)		199		19		19		19		19			19			104

Total, net			$	1,953	$	(1,017	)	$	936	$	437	$	117	$	62	$	12		$	21		$	287

(a)	Includes the fair value of BGE’s power and gas supply contracts for which an offsetting Exelon Corporate regulatory asset was also recorded.

Impact of Merger

It is impracticable to determine the current quarter and year-to-date overall financial statement impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger. Upon closing of the merger, the operations of these Constellation subsidiaries were integrated into Generation’s operations and are therefore not fully distinguishable after the merger.

The impact of BGE on Exelon’s Consolidated Statement of Operations and Comprehensive Income includes operating revenues of $2,091 million and net loss of $31 million during the year ended December 31, 2012.

During the year ended December 31, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $746 million, $340 million, $5 million, $17 million and $160 million, respectively. These amounts do not include merger and integration-related costs of $36 million and $22 million incurred at ComEd and BGE, respectively, which have been recorded as a regulatory asset. The costs incurred are classified primarily within Operating and Maintenance Expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the BGE customer rate credit and the credit facility fees, which are included as a reduction to operating revenues and other, net, respectively, for the year ended December 31, 2012.

During the year ended December 31, 2011, Exelon, Generation and PECO incurred merger and integration-related costs of $77 million, $15 million and $2 million, respectively. These costs are classified primarily within Operating and Maintenance Expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income.

Severance Costs

The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

267

Combined Notes to Consolidated Financial Statements—(Continued)

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

Upon closing the merger with Constellation, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon has identified specific employees to be severed pursuant to the merger-related staffing and selection process; as well as employees that were previously identified for severance but have since accepted another position within Exelon and are no longer receiving a severance benefit. Exelon adjusts its accrual each quarter to reflect its best estimate of remaining severance costs. The amount of severance expense associated with the post-merger integration recognized through December 31, 2012, for Exelon is $138 million, which includes $88 million, $16 million, $7 million and $19 million for Generation, ComEd, PECO and BGE, respectively. Estimated costs to be incurred after December 31, 2012 are not material. In addition, certain employees identified during the staffing and selection process also receive pension and other postretirement benefits that are deemed contractual termination benefits. See Note 14—Retirement Benefits for additional information on the contractual termination benefits.

For the year ended December 31, 2012, the Registrants recorded the following severance benefits costs associated with the identified job reductions within operating and maintenance expense in their Consolidated Statements of Operations, except for ComEd and BGE:


Year Ended December 31, 2012
Severance Benefits ^(a)	Exelon		Generation		ComEd ^(b)		PECO		BGE ^(c)
Severance charges	$	124	$	80	$	14	$	7	$	17
Stock compensation		7		4		1		—		1
Other charges		7		4		1		—		1

Total severance benefits	$	138	$	88	$	16	$	7	$	19

(a)	The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.

(b)	ComEd established regulatory assets of $16 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.

(c)	Consistent with MDPSC precedent, BGE established a regulatory asset of $19 million, as of December 31, 2012, for severance benefits costs. The majority of these costs are expected to be recovered over a five-year period.

Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations:


Year Ended December 31, 2012
Severance liability	Exelon			Generation			ComEd			PECO		BGE
Balance at December 31, 2011	$	—		$	—		$	—		$	—	$	—
Severance charges ^(a)		124			38			2			—		11
Stock compensation		7			2			—			—		—
Other charges ^(b)		7			2			—			—		1
Payments		(27	)		(9	)		(1	)		—		(1	)

Balance at December 31, 2012	$	111		$	33		$	1		$	—	$	11

(a)

Includes salary continuance and health and welfare severance benefits. Amounts represent ongoing severance plan benefits. Amounts also include one-time termination benefits of $3 million and $1 million for Exelon and Generation, respectively, which they began to recognize in the second quarter of 2012.

(b)	Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services.

268

Combined Notes to Consolidated Financial Statements—(Continued)

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

Cash payments under the plan began in the second quarter of 2012. Substantially all cash payments under the plan are expected to be made by the end of 2016.

Pro-forma Impact of the Merger

The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon and Generation as if the merger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after applying Exelon’s and Generation’s accounting policies and adjusting Constellation’s, including BGE’s as appropriate, results to reflect purchase accounting adjustments.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.


	Generation				Exelon
	Year Ended December 31,				Year Ended December 31,
(unaudited)	2012		2011 ^(a)		2012		2011 ^(b)
Total Revenues	$	17,013	$	19,494	$	26,700	$	30,712
Net income attributable to Exelon		1,205		324		2,092		974
Basic Earnings Per Share		n.a.		n.a.	$	2.56	$	1.15
Diluted Earnings Per Share		n.a.		n.a.		2.55		1.14

(a)	The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011.

(b)	The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011.

Acquisitions (Exelon and Generation)

Consistent with the applicable accounting guidance, the fair value of the assets acquired and liabilities assumed was determined as of the acquisition date through the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and assumptions used include: projected future cash flows (including the amount and timing); discount rates reflecting the risk inherent in the future cash flows; and future power and fuel market prices. Additionally, market prices based on the Market Price Referent (MPR) established by the CPUC for renewable energy resources were used in determining the fair value of the Antelope Valley assets acquired and liabilities assumed. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and the duration of the liabilities assumed. Generation did not record any goodwill related to any of the respective acquisitions.

269

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for each of the companies acquired by Generation during the years ended December 31, 2011 and December 31, 2010:


	Acquisitions
	2011						2010
	Wolf Hollow			Antelope Valley			Exelon Wind
Fair value of consideration transferred
Cash	$	305		$	75		$	893
Plus: Gain on PPA settlement		6			—			—
Contingent consideration		—			—			32

Total fair value of consideration transferred	$	311		$	75		$	925

Recognized amounts of identifiable assets acquired and liabilities assumed
Property, plant and equipment	$	347		$	15		$	700
Inventory		5			—			—
Intangible assets ^(a)		—			190			224
Payable to First Solar, Inc. ^(b)		—			(135	)		—
Working capital, net		(5	)		—			18
Asset retirement obligations		—			—			(13	)
Noncontrolling interest		—						(3	)
Other Assets		—			5			(1	)

Total net identifiable assets	$	347		$	75		$	925

Bargain purchase gain	$	36		$	—		$	—

(a)	See Note 8—Intangible Assets for additional information.

(b)

Generation concluded that the remaining, yet-to-be paid $135 million in consideration was embedded in the amounts payable under the Engineering, Procurement, Construction (EPC) agreement for First Solar, Inc. to construct the solar facility. For accounting purposes, this aspect of the transaction is considered to be akin to a “seller financing” arrangement. As such, Generation recorded a liability of $135 million associated with the portion of the future payments to First Solar, Inc. under the EPC agreement to reflect Generation’s implicit amounts due First Solar, Inc. for the remainder of the value of the net assets acquired. The $135 million payable to First Solar, Inc. will be relieved as Generation makes payments for costs incurred over the project construction period. At December 31, 2012, $87 million remained payable to First Solar, Inc.

Wolf Hollow, LLC. On August 24, 2011, Generation completed the acquisition of all of the equity interests of Wolf Hollow, LLC (Wolf Hollow), a combined-cycle natural gas-fired power plant in north Texas, for a purchase price of $311 million which increased Generation’s owned capacity within the ERCOT power market by 720 MWs. The acquisition supports the Exelon commitment to renewable energy as part of Exelon 2020.

Generation recognized an approximately $36 million non-cash bargain purchase gain (i.e., negative goodwill). The gain was included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The pro forma impact of this acquisition would not have been material to Exelon’s or Generation’s results of operations for the years ended December 31, 2011 and 2010.

270

Combined Notes to Consolidated Financial Statements—(Continued)

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

Antelope Valley Solar Ranch One. On September 30, 2011, Generation acquired Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project under development in northern Los Angeles County, California, from First Solar, which developed and will build, operate, and maintain the project. The first block began operations in December 2012, with three additional blocks coming online in February 2013 and an expectation of full commercial operation by the end of the third quarter of 2013. When fully operational, Antelope Valley will be one of the largest PV solar projects in the world, with approximately 3.8 million solar panels generating enough clean, renewable electricity to power the equivalent of 75,000 average homes per year. The project has a 25-year PPA, approved by the California Public Utilities Commission, with Pacific Gas & Electric Company for the full output of the plant. The acquisition supports Exelon’s commitment to renewable energy as part of Exelon 2020.

Exelon expects to invest up to $701 million in equity in the project through 2013. The DOE’s Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the project. On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million and terminated the put option that Generation had on the Antelope Valley project. See Note 11—Debt and Credit Agreements for additional information on the DOE loan guarantee.

The pro forma impact of this acquisition would not have been material to Exelon’s or Generation’s results of operations for the years ended December 31, 2011 and 2010.

Exelon Wind. On December 9, 2010, Generation paid consideration of $893 million to complete the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power. Under the terms of the agreement, Generation added 735 MWs of installed, operating wind capacity located in eight states. The acquisition supports Exelon’s commitment to renewable energy as part of Exelon 2020.

The contingent consideration arrangement requires that Generation pay up to $40 million related to three individual projects with an aggregate capacity of 230 MWs, contingent upon meeting certain contractual commitments related to the commencement of construction of each project. The fair value of the contingent consideration arrangement of $32 million was determined as of the acquisition date based upon a weighted average probability of meeting certain contractual commitments related to the commencement of construction of each project, which is considered an unobservable (Level 3) input pursuant to applicable accounting guidance. During the third quarter of 2011, $16 million of contingent consideration was paid to Deere & Company for one of the projects and the probability of a second project beginning construction, Harvest II, was increased to 100%. As a result, the contingent consideration included in other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets was adjusted to $10 million to reflect the full expected contingent payment related to the Harvest II project and subsequently paid to Deere & Company during the third quarter of 2012. Additionally, $2 million was recorded in operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The remaining $8 million of contingent consideration is included in other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

The fair value of the assets acquired included customer receivables of $18 million. There are no outstanding customer receivables that were acquired in the Exelon Wind transaction.

The $3 million noncontrolling interest represents the noncontrolling members’ proportionate share in the fair value of the assets acquired and liabilities assumed in the transaction.

271

Combined Notes to Consolidated Financial Statements—(Continued)

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

The pro forma impact of this acquisition would not have been material to Exelon’s or Generation’s results of operations for the year ended December 31, 2010.

5. Accounts Receivable (Exelon, Generation, ComEd PECO and BGE)

Accounts receivable at December 31, 2012 and 2011 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:


2012	Exelon			Generation			ComEd			PECO			BGE
Unbilled customer revenues	$	1,418		$	859		$	213		$	164		$	182
Allowance for uncollectible accounts ^(a)		(293	)		(84	)		(70	)		(99	)^(b)		(40	)


2011	Exelon			Generation			ComEd			PECO			BGE
Unbilled customer revenues	$	902		$	493		$	246		$	163		$	194
Allowance for uncollectible accounts ^(a)		(199	)		(29	)		(78	)		(92	)^(b)		(37	)

(a)	Includes the allowance for uncollectible accounts on customer and other accounts receivable.

(b)	Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2012 and 2011, respectively, related to PECO’s current installment plan receivables described below.

PECO Installment Plan Receivables (Exelon and PECO). PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $18 million and $21 million as of December 31, 2012 and 2011, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1—Significant Accounting Policies. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2012 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2011 of $17 million consists of $1 million, $3 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of December 31, 2012 and 2011 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1—Significant Accounting Policies.

Accounts Receivable Agreement (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, which is accounted for as a secured borrowing. On November 28, 2012, PECO made a principal paydown of $15 million to meet the compliance requirements for the October 2012 reporting period. The remaining principal balance of $210 million is classified as a short-

272

Combined Notes to Consolidated Financial Statements—(Continued)

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

term note payable on Exelon’s and PECO’s Consolidated Balance Sheets. As of December 31, 2012 and 2011, the financial institution’s undivided interest in PECO’s gross accounts receivable was equivalent to $289 million and $329 million, respectively, which is calculated under the terms of the agreement. See Note 11—Debt and Credit Agreements for additional information regarding the accounts receivable agreement.

6. Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)

Exelon

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:


	Average Service Life (years)	2012		2011
Asset Category
Electric—transmission and distribution	5 - 90	$	26,576	$	21,716
Electric—generation ^(a)	1 - 53		19,004		13,682
Gas—transportation and distribution	5 - 90		3,108		1,793
Common—electric and gas	5 - 50		1,029		564
Nuclear fuel ^(b)	1 - 8		4,815		4,225
Construction work in progress	N/A		1,926		1,110
Other property, plant and equipment ^(c)	3 - 72		912		439

Total property, plant and equipment			57,370		43,529
Less: accumulated depreciation ^(d)			12,184		10,959

Property, plant and equipment, net		$	45,186	$	32,570

(a)	Includes assets acquired through acquisitions. See Note 4—Mergers and Acquisitions for additional information.

(b)	Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.

(c)

Includes Generation’s buildings under capital lease with a net carrying value of $20 million and $23 million at December 31, 2012 and 2011, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $33 million and $30 million as of December 31, 2012 and 2011, respectively. Also includes land held for future use and non utility property at ComEd, PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation.

(d)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,078 million and $1,784 million as of December 31, 2012 and 2011, 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	2012			2011			2010
Electric—transmission and distribution		2.76	%		2.59	%		2.53	%
Electric—generation		3.15	%		3.12	%		2.86	%
Gas		2.03	%		1.73	%		1.75	%
Common—electric and gas		7.61	%		8.05	%		7.25	%

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:


	Average Service Life (years)	2012		2011
Asset Category
Electric—generation ^(a)	1 - 53	$	19,004	$	13,682
Nuclear fuel ^(b)	1 - 8		4,815		4,225
Construction work in progress	N/A		1,352		827
Other property, plant and equipment ^(c)	5 - 57		374		54

Total property, plant and equipment			25,545		18,788
Less: accumulated depreciation ^(d)			6,014		5,313

Property, plant and equipment, net		$	19,531	$	13,475

(a)	Includes assets acquired through acquisitions. See Note 4—Mergers and Acquisitions for additional information.

(b)	Includes nuclear fuel that is in the fabrication and installation phase of $894 million and $674 million at December 31, 2012 and 2011, respectively.

(c)

Includes buildings under capital lease with a net carrying value of $20 million and $23 million at December 31, 2012 and 2011, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $33 million and $30 million as of December 31, 2012 and 2011, respectively.

(d)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,078 million and $1,784 million as of December 31, 2012 and 2011, respectively.

The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.15%, 3.12% and 2.86% for the years ended December 31, 2012, 2011 and 2010, 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 (except for Oyster Creek) and the hydroelectric generating stations. As a result, the receipt of license renewals has no impact on the Consolidated Statements of Operations. See Note 3—Regulatory Matters for additional information regarding license renewals.

ComEd

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:


	Average Service Life (years)	2012		2011
Asset Category
Electric—transmission and distribution	5 - 75	$	16,480	$	15,637
Construction work in progress	N/A		294		187
Other property, plant and equipment ^(a)	72		50		47

Total property, plant and equipment			16,824		15,871
Less: accumulated depreciation			2,998		2,750

Property, plant and equipment, net		$	13,826	$	13,121

(a)	Represents land held for future use and non utility property.

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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 transmission and distribution assets were 2.79%, 2.67% and 2.64% for the years ended December 31, 2012, 2011 and 2010, respectively.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:


	Average Service Life (years)	2012		2011
Asset Category
Electric—transmission and distribution	5 - 65	$	6,355	$	6,079
Gas—transportation and distribution	5 - 70		1,859		1,793
Common—electric and gas	5 - 50		568		564
Construction work in progress	N/A		76		83
Other property, plant and equipment ^(a)	50		17		17

Total property, plant and equipment			8,875		8,536
Less: accumulated depreciation			2,797		2,662

Property, plant and equipment, net		$	6,078	$	5,874

(a)	Represents land held for future use and non utility property.

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	2012			2011			2010
Electric—transmission and distribution		2.51	%		2.33	%		2.17	%
Gas		1.77	%		1.73	%		1.75	%
Common—electric and gas		7.54	%		8.05	%		7.25	%

BGE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2012 and 2011:


	Average Service Life (years)	2012		2011
Asset Category
Electric—transmission and distribution	5 - 90	$	5,767	$	5,483
Gas—transmission and distribution	5 - 90		1,548		1,387
Common—electric and gas	5 - 40		554		415
Construction work in progress	N/A		193		298
Other property, plant and equipment ^(a)	20		31		15

Total property, plant and equipment			8,093		7,598
Less: accumulated depreciation			2,595		2,466

Property, plant and equipment, net		$	5,498	$	5,132

(a)	Represents land held for future use and non utility property.

275

Combined Notes to Consolidated Financial Statements—(Continued)

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


Average Service Life Percentage by Asset Category	2012			2011			2010
Electric—transmission and distribution		2.92	%		2.89	%		2.88	%
Gas		2.33	%		2.41	%		2.42	%
Common—electric and gas		7.68	%		8.40	%		7.24	%

See Note 1—Significant Accounting Polices for further information regarding property, plant and equipment policies and accounting for capitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 11—Debt and Credit Agreements for further information regarding Exelon’s, ComEd’s, and PECO’s property, plant and equipment subject to mortgage liens.

7. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)

Exelon, Generation, PECO and BGE’s undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2012 and 2011 were as follows:


	Nuclear generation									Fossil fuel generation									Transmission					Other
	Quad Cities			Peach Bottom			Salem ^(a)			Keystone ^(b)			Conemaugh ^(b)			Wyman			PA ^(c)		DE/NJ ^(d)			Other ^(e)
Operator		Generation			Generation			PSEG Nuclear			GenOn			GenOn			FP&L			First Energy		PSEG
Ownership interest		75.00	%		50.00	%		42.59	%		41.98	%		31.28	%		5.89	%		Various		42.55	%		44.24	%
Exelon’s share at December 31, 2012:
Plant ^(f)	$	874		$	796		$	494		$	624		$	322		$	3		$	13	$	65		$	1
Accumulated depreciation ^(f)		187			302			119			153			158			3			7		33			—
Construction work in progress		44			115			11			10			57			—			1		—			—
Exelon’s share at December 31, 2011:
Plant ^(f)	$	822		$	650		$	420		$	366		$	271		$	3		$	5	$	66		$	1
Accumulated depreciation ^(f)		156			285			103			137			154			3			3		33			—
Construction work in progress		37			111			61			5			15			—			—		—			—

(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, 2012 and 2011.

(b)	Generation’s ownership interest in Keystone and Conemaugh has increased as a result of Exelon’s merger with Constellation in 2012. See Note 4 for additional information.

(c)

PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500 kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500 kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500 kV lines including, but not limited to, the lines noted above.

(d)

PECO owns a 42.55% share in 131 miles of 500 kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.

(e)	Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey.

(f)	Excludes asset retirement costs.

Exelon’s, Generation’s, PECO’s and BGE’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, PECO’s and BGE’s share of direct expenses of the jointly owned

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 and BGE’s Consolidated Statements of Operations.

8. 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, 2012 and 2011 were as follows:


	2012 and 2011
	Gross Amount ^(a)		Accumulated Impairment Losses		Carrying Amount
Balance, January 1,	$	4,608	$	1,983	$	2,625
Impairment losses		—		—		—

Balance, December 31,	$	4,608	$	1,983	$	2,625

(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) 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 is more likely than not impaired, such as a significant negative regulatory outcome, that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount.

In September 2011, the FASB issued authoritative guidance amending existing guidance on the annual assessment of goodwill for impairment. Under the revised guidance, which became effective January 1, 2012, entities assessing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step fair value based impairment test). If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step fair value based impairment test is required. Otherwise, no further testing is required.

If an entity bypasses the qualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount, a two-step, fair value based test is performed. 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. Under the effective authoritative guidance for fair value measurement, Exelon and ComEd estimate the fair value of the ComEd reporting unit using a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case”

277

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows from ComEd’s business and the fair value of debt. 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.

2012 Interim Goodwill Impairment Assessment. In May 2012, the ICC issued a final Order (Order) in ComEd’s 2011 formula rate proceeding under EIMA that reduced ComEd’s annual revenue requirement being recovered in current rates by $168 million. Management concluded that the Order represented an event that required an interim goodwill impairment assessment and as a result, ComEd tested its goodwill for impairment as of May 31, 2012. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. Consistent with prior annual impairment tests, the estimated fair value of ComEd was determined using a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case” or management’s best estimate of projected cash flows for ComEd’s business. In performing the discounted cash flow analysis for the interim goodwill test, management assumed that ComEd would ultimately prevail in appealing certain aspects of the May Order, specifically the return on ComEd’s pension asset and the use of year-end rate base in determining ComEd’s annual revenue requirement being recovered in current rates. The disallowances related to the pension asset return and year-end rate base were estimated to reduce ComEd’s revenue requirement recovered in rates by approximately $75—$130 million annually. The assessment also reflected several favorable changes in certain market assumptions since the annual impairment assessment in 2011, including the weighted average cost of capital and market multiples.

Based on the results of the interim goodwill test, the estimated fair value of ComEd would have needed to decrease by more than 10 percent for ComEd to fail the first step of the impairment test.

On October 3, 2012, the ICC issued its Rehearing Order in response to ComEd’s expedited rehearing request. The Rehearing Order adopted ComEd’s position on the return on its pension asset resulting in an increase in ComEd’s annual revenue. See Note 3—Regulatory Matters for further detail.

2012 Annual Goodwill Impairment Assessment. ComEd performed a qualitative assessment as of November 1, 2012, for its 2012 annual goodwill impairment assessment and while certain factors indicated a reduction in fair value since May 31, 2012, ComEd determined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform a quantitative assessment. As part of its qualitative assessment, ComEd evaluated, among other things, management’s best estimate of projected operating and capital cash flows for ComEd’s business (including the impacts of the Rehearing Order) as well as changes in certain other market conditions such as the discount rate and EBITDA multiples.

While neither the interim nor the annual assessments indicated an impairment of ComEd’s goodwill, a change in management’s assumption regarding the outcome of the IRS’ challenge of Exelon’s and

278

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd’s like-kind exchange income tax position, adverse regulatory actions such as early termination of EIMA, or changes in the significant assumptions described above could potentially result in a future impairment of ComEd’s goodwill, which could be material. ComEd will assess whether its goodwill has been impaired in the first quarter of 2013 in connection with the reassessment of the like-kind exchange position and the associated charge to ComEd’s earnings. See Note 12 for additional information.

Prior Goodwill Impairment Assessments. The 2011 and 2010 annual goodwill impairment assessments were performed as of November 1, 2011 and November 1, 2010, respectively. In each case, 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. ComEd will assess whether its goodwill has been impaired in the first quarter of 2013 in connection with the reassessment of the like-kind exchange position and the charge to ComEd’s earnings. See Note 12 for additional information.

Other Intangible Assets

For discussion surrounding Exelon’s and Generation’s unamortized energy contracts, trade name and retail relationships recorded in conjunction with the Merger refer to Note 4—Merger and Acquisitions.

Exelon’s, Generation’s and ComEd’s other intangible assets, included in unamortized energy contract assets and deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2012:


								Estimated amortization expense
	Gross		Accumulated Amortization			Net		2013		2014		2015		2016		2017
Generation
Exelon Wind acquisition ^(a)	$	224	$	(26	)	$	198	$	14	$	14	$	14	$	14	$	14
Antelope Valley acquisition ^(b)		190		—			190		7		8		8		8		8
ComEd
Chicago settlement–1999 agreement ^(c)		100		(72	)		28		3		3		3		3		4
Chicago settlement–2003 agreement ^(d)		62		(34	)		28		4		4		4		4		3

Total intangible assets	$	576	$	(132	)	$	444	$	28	$	29	$	29	$	29	$	29

(a)	Refer to Note 4—Merger and Acquisitions for additional information regarding Exelon Wind.

(b)	Refer to Note 4—Merger and Acquisitions for additional information regarding Antelope Valley.

(c)

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 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.

(d)

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. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under the 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.

279

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table summarizes the amortization expense related to intangible assets for each of the years ended December 31, 2012, 2011 and 2010:


For the Year Ended December 31,	Exelon		Generation		ComEd
2012	$	20	$	13	$	7
2011		19		12		7
2010		8		1		7

Acquired Intangible Assets

Accounting guidance for business combinations requires that the acquirer must recognize separately identifiable intangible assets in the application of purchase accounting. The valuation of the acquired intangible assets discussed below were estimated by applying the income approach, which is based upon discounted projected future cash flows associated with the respective PPAs. Those measures are based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance.

Exelon Wind. The output of the acquired wind turbines has been sold under PPA contracts. The excess of the contract price of the PPAs over market prices was recognized as intangible assets at the acquisition date. Generation determined that the estimated acquisition-date fair value of the intangible assets was approximately $224 million, which is recorded in unamortized energy contract assets within Exelon’s and Generation’s Consolidated Balance Sheets.

Key assumptions used in the valuation of the intangible assets include forecasted power prices and discount rate. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. The intangible assets are amortized on a straight-line basis over the period in which the associated contract revenues are recognized. The amortization expense is reflected as a decrease in operating revenue within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The weighted-average amortization period for these intangibles is approximately 18 years.

Antelope Valley. Upon completion of the development project, all of the output will be sold under a PPA with Pacific Gas & Electric Company. The excess of the contract price of the PPA over forecasted MPR-based market prices was recognized as an intangible asset at the acquisition date. Generation determined that the estimated acquisition-date fair value of the intangible asset was approximately $190 million, which is recorded in unamortized energy contract assets within Exelon’s and Generation’s Consolidated Balance Sheets. While Generation expects to perform under the PPA once the construction of this project is complete, there is a risk of impairment if the project does not reach commercial operation.

Key assumptions used in the valuation of the intangible asset include forecasted MPR-based market prices and discount rate. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. The fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition date. The intangible asset will be amortized as a decrease in operating revenue within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income over the 25 year term of the underlying PPA.

280

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, ComEd and PECO).

Exelon’s, Generation’s, ComEd’s and PECO’s other intangible assets, included in other current assets and other deferred debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon, Generation and ComEd) and AECs (Exelon and PECO). Revenue for RECs that are part of a bundled power sale is recognized when the power is produced and delivered to the customer. As of December 31, 2012, and 2011, PECO had current AECs of $17 million and $14 million, respectively, and noncurrent AECs of $9 million and $16 million, respectively. As of December 31, 2012, and 2011, Generation had current RECs of $61 million and $0 million, respectively, and noncurrent RECs of $45 million and $6 million, respectively. As of December 31, 2012, and 2011, ComEd, had current RECs of $18 million and $9 million, respectively, and noncurrent RECs of $49 million and $97, respectively. See Notes 1—Significant Accounting Policies, 3—Regulatory Matters and Note 19—Commitments and Contingencies for additional information on RECs and AECs.

9. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)

Fair Value of Financial Liabilities Recorded at the Carrying Amount

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, trust preferred securities (long-term debt to financing trusts or junior subordinated debentures), and preferred securities as of December 31, 2012, and 2011:

Exelon


	December 31, 2012								December 31, 2011
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Carrying Amount		Fair Value
Short-term liabilities	$	214	$	4	$	210	$	—	$	737	$	737
Long-term debt (including amounts due within one year)		18,745		—		20,244		276		12,627		14,488
Long-term debt to financing trusts		648		—		—		664		390		358
SNF obligation		1,020		—		763		—		1,019		886
Preferred securities of subsidiary		87		—		82		—		87		79

Generation


	December 31, 2012								December 31, 2011
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Carrying Amount		Fair Value
Short-term liabilities	$	—	$	—	$	—	$	—	$	2	$	2
Long-term debt (including amounts due within one year)		7,483		—		7,591		258		3,677		4,231
SNF obligation		1,020		—		763		—		1,019		886

281

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd


	December 31, 2012								December 31, 2011
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	5,567	$	—	$	6,530	$	18	$	5,665	$	6,540
Long-term debt to financing trust		206		—		—		212		206		184

PECO


	December 31, 2012								December 31, 2011
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Carrying Amount		Fair Value
Short-term liabilities	$	210	$	—	$	210	$	—	$	225	$	225
Long-term debt (including amounts due within one year)		1,947		—		2,264		—		1,972		2,295
Long-term debt to financing trusts		184		—		—		188		184		174
Preferred securities		87		—		82		—		87		79

BGE


	December 31, 2012								December 31, 2011
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,178	$	—	$	2,468	$	—	$	2,101	$	2,377
Long-term debt to financing trusts		258		—		—		263		258		256

Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of short-term borrowings (Level 2), short-term notes payable related to PECO’s accounts receivable agreement (Level 2), and dividends payable (Level 1). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments. See Note 11—Debt and Credit Agreements for additional information on PECO’s accounts receivable agreement.

Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.

282

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation has fixed rate project financing debt (Level 3), the fair value of which is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, for certain government-backed debt, discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a quarterly basis and the carrying value approximates fair value.

The Registrants also have tax-exempt debt (Level 3). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (i.e., political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above.

SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025.

Long-Term Debt to Financing Trusts. Due to low trading volume of similar securities (Level 3), qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, may be incorporated into the credit spreads that are used to obtain the fair value as described above.

Preferred Securities. The fair value of these securities is determined based on the last closing price prior to quarter end, less accrued interest. The securities are registered with the SEC and are public.

Recurring Fair Value Measurements

Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy 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, certain exchange-based derivatives, 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 and mutual investment funds priced at NAV per fund share and fair value hedges.

•

Level 3—unobservable inputs, such as internally developed pricing models or third party valuations 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, investments priced using an alternative pricing mechanism, and middle market lending using third party valuations.

There were no transfers between Level 1 and Level 2 during the year ended December 31, 2012.

283

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon

The following tables present 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, 2012 and December 31, 2011:


As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	995	$	—	$	—	$	995
Nuclear decommissioning trust fund investments
Cash equivalents		245		—		—		245
Equity
Equity securities		1,480		—		—		1,480
Commingled funds		—		1,933		—		1,933

Equity funds subtotal		1,480		1,933		—		3,413

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,057		—		—		1,057
Debt securities issued by states of the United States and political subdivisions of the states		—		321		—		321
Debt securities issued by foreign governments		—		93		—		93
Corporate debt securities		—		1,788		—		1,788
Federal agency mortgage-backed securities		—		24		—		24
Commercial mortgage-backed securities (non-agency)		—		45		—		45
Residential mortgage-backed securities (non-agency)		—		11		—		11
Mutual funds		—		23		—		23

Fixed income subtotal		1,057		2,305		—		3,362

Middle market lending		—		—		183		183
Other debt obligations		—		15		—		15

Nuclear decommissioning trust fund investments subtotal^(b)		2,782		4,253		183		7,218

Pledged assets for Zion decommissioning
Cash equivalents		—		23		—		23
Equity
Equity securities		14		—		—		14
Commingled funds		—		9		—		9

Equity funds subtotal		14		9		—		23

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		118		12		—		130
Debt securities issued by states of the United States						—
and political subdivisions of the states		—		37		—		37
Corporate debt securities		—		249		—		249
Federal agency mortgage-backed securities		—		49		—		49
Commercial mortgage-backed securities (non-agency)		—		6		—		6

Fixed income subtotal		118		353		—		471

Middle market lending		—		—		89		89
Other debt obligations		—		1		—		1

284

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2012	Level 1			Level 2			Level 3			Total
Pledged assets for Zion decommissioning subtotal^(c)		132			386			89			607

Rabbi trust investments
Cash equivalents		2			—			—			2
Mutual funds^(d)		69			—			—			69

Rabbi trust investments subtotal		71			—			—			71

Commodity mark-to-market derivative assets
Economic hedges		861			3,173			641			4,675
Proprietary trading		1,042			2,078			73			3,193
Effect of netting and allocation of collateral^(f)		(1,823	)		(4,175	)		(58	)		(6,056	)

Commodity mark-to-market assets subtotal^(g)		80			1,076			656			1,812
Interest rate mark-to-market derivative assets		—			114			—			114
Effect of netting and allocation of collateral		—			(51	)		—			(51	)

Interest rate mark-to-market derivative assets subtotal		—			63			—			63
Other Investments		2			—			17			19

Total assets		4,062			5,778			945			10,785

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,041	)		(2,289	)		(236	)		(3,566	)
Proprietary trading		(1,084	)		(1,959	)		(78	)		(3,121	)
Effect of netting and allocation of collateral^(f)		2,042			4,020			25			6,087

Commodity mark-to-market liabilities subtotal^(g)(h)		(83	)		(228	)		(289	)		(600	)

Interest rate mark-to-market derivative liabilities		—			(84	)		—			(84	)
Effect of netting and allocation of collateral		—			51			—			51

Interest rate mark-to-market derivative liabilities subtotal		—			(33	)		—			(33	)
Deferred compensation		—			(102	)		—			(102	)

Total liabilities		(83	)		(363	)		(289	)		(735	)

Total net assets	$	3,979		$	5,415		$	656		$	10,050

285

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	861	$	—	$	—	$	861
Nuclear decommissioning trust fund investments
Cash equivalents		562		—		—		562
Equity
Equity securities		1,275		—		—		1,275
Commingled funds		—		1,822		—		1,822

Equity funds subtotal		1,275		1,822		—		3,097

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,014		33		—		1,047
Debt securities issued by states of the United States and political subdivisions of the states		—		541		—		541
Debt securities issued by foreign governments		—		16		—		16
Corporate debt securities		—		778		—		778
Federal agency mortgage-backed securities		—		357		—		357
Commercial mortgage-backed securities (non-agency)		—		83		—		83
Residential mortgage-backed securities (non-agency)		—		5		—		5
Mutual funds		—		47		—		47

Fixed income subtotal		1,014		1,860		—		2,874

Middle market lending		—		—		13		13
Other debt obligations		—		18		—		18

Nuclear decommissioning trust fund investments subtotal^(b)		2,851		3,700		13		6,564

Pledged assets for Zion decommissioning Equity
Equity securities		35		—		—		35
Commingled funds		—		30		—		30

Equity funds subtotal		35		30		—		65

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		54		26		—		80
Debt securities issued by states of the United States and political subdivisions of the states		—		65		—		65
Corporate debt securities		—		314		—		314
Federal agency mortgage-backed securities		—		121		—		121
Commercial mortgage-backed securities (non-agency)		—		10		—		10
Commingled funds		—		20		—		20

Fixed income subtotal		54		556		—		610

Middle market lending		—		—		37		37
Other debt obligations		—		13		—		13

Pledged assets for Zion decommissioning subtotal^(c)		89		599		37		725

Rabbi trust investments
Cash equivalents		2		—		—		2
Mutual funds^(d)(e)		34		—		—		34

286

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2011	Level 1			Level 2			Level 3			Total
Rabbi trust investments subtotal		36			—			—			36

Commodity mark-to-market derivative assets
Cash flow hedges		—			857			—			857
Economic hedges		—			1,653			124			1,777
Proprietary trading		—			240			48			288
Effect of netting and allocation of collateral^(f)		—			(1,827	)		(28	)		(1,855	)

Commodity mark-to-market assets^(g)		—			923			144			1,067

Interest rate mark-to-market derivative assets		—			15			—			15

Total assets		3,837			5,237			194			9,268

Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		—			(13	)		—			(13	)
Economic hedges		(1	)		(1,137	)		(119	)		(1,257	)
Proprietary trading		—			(236	)		(28	)		(264	)
Effect of netting and allocation of collateral^(f)		—			1,295			20			1,315

Commodity mark-to-market liabilities^(h)		(1	)		(91	)		(127	)		(219	)

Interest rate mark-to-market liabilities		—			(19	)		—			(19	)

Deferred compensation		—			(73	)		—			(73	)

Total liabilities		(1	)		(183	)		(127	)		(311	)

Total net assets	$	3,836		$	5,054		$	67		$	8,957

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Excludes net assets (liabilities) of $30 million and $(57) million at December 31, 2012 and December 31, 2011, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(c)	Excludes net assets of $7 million and $9 million at December 31, 2012 and December 31, 2011, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d)	The mutual funds held by the Rabbi trusts include $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan. These funds are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(e)	Excludes $28 million and $25 million of the cash surrender value of life insurance investments at December 31, 2012 and December 31, 2011, respectively.

(f)

Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $532 million and $8 million allocated to Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2011.

(g)

The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million and $0 million at December 31, 2012 and $503 million and $191 million at December 31, 2011, respectively, related to the fair value of Generation’s financial swap contract with ComEd.

(h)	The Level 3 balance includes the current and noncurrent liability of $18 million and $49 million at December 31, 2012, respectively, and $9 million and $97 million at December 31, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

287

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2012 and 2011:


For the Year Ended December 31, 2012	Nuclear Decommissioning Trust Fund Investment		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives ^(b)			Other Investments		Total
Balance as of January 1, 2012	$	13	$	37		$	17		$	—	$	67
Total realized / unrealized gains (losses)
Included in net income		—		—			(119	) ^(a)		—		(119	)
Included in other comprehensive income		—		—			—			—		—
Included in regulatory assets		1		—			39			—		40
Included in payable for Zion Station decommissioning		—		—			—			—		—
Change in collateral		—		—			(32	)		—		(32	)
Purchases, sales, issuances and settlements
Purchases		169		63			334	^(c)		17		583
Sales		—		(11	)		—			—		(11	)
Transfers into Level 3		—		—			39			—		39
Transfers out of Level 3		—		—			89			—		89

Balance as of December 31, 2012	$	183	$	89		$	367		$	17	$	656

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2012	$	—	$	—		$	37		$	—	$	37

(a)	Includes the reclassification of $156 million of realized losses due to settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012.

(b)

Excludes $98 million of increases in fair value and $566 million of realized losses due to settlements for the year ended December 31, 2012 of Generation’s financial swap contract with ComEd, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI.

(c)	Includes $323 million of fair value from contracts and $17 million of other investments acquired as a result of the merger.

288

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2011	Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Decommissioning			Mark-to-Market Derivatives			Total
Balance as of January 1, 2011	$	—	$	—		$	50		$	50
Total realized / unrealized gains (losses)
Included in income		1		—			99			100
Included in other comprehensive income		—		—			(25	)^(a)		(25	)
Included in regulatory liabilities		2		—			(106	)^(b)		(104	)
Change in collateral		—		—			6			6
Purchases, sales, issuances and settlements
Purchases		10		60			10			80
Sales		—		(23	)		—			(23	)
Transfers out of Level 3		—		—			(17	)		(17	)

Balance as of December 31, 2011	$	13	$	37		$	17		$	67

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2011	$	1	$	—		$	131		$	132

(a)	Includes the reclassification of $32 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2011.

(b)

Excludes $170 million of increases in fair value and $451 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd and $5 million of changes in the fair value of Generation’s block contracts with PECO for the year ended December 31, 2011. All items eliminate upon consolidation if Exelon’s Consolidated Financial Statements.

The following tables present the income statement classification of the 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, 2012 and 2011:


	Operating Revenue			Purchased Power and Fuel
Total gains (losses) included in income for the year ended December 31, 2012	$	(153	)	$	34
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2012	$	13		$	24

	Operating Revenue			Purchased Power and Fuel
Total gains (losses) included in income for the year ended December 31, 2011	$	108		$	(8	)
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2011	$	137		$	(5	)

289

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation

The following tables present 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, 2012 and December 31, 2011:


As of December 31, 2012	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	487	$	—	$	—	$	487
Nuclear decommissioning trust fund investments
Cash equivalents		245		—		—		245
Equity
Equity securities		1,480		—		—		1,480
Commingled funds		—		1,933		—		1,933

Equity funds subtotal		1,480		1,933		—		3,413

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,057		—		—		1,057
Debt securities issued by states of the United States and political subdivisions of the states		—		321		—		321
Debt securities issued by foreign governments		—		93		—		93
Corporate debt securities		—		1,788		—		1,788
Federal agency mortgage-backed securities		—		24		—		24
Commercial mortgage-backed securities (non-agency)		—		45		—		45
Residential mortgage-backed securities (non-agency)		—		11		—		11
Mutual funds		—		23		—		23

Fixed income subtotal		1,057		2,305		—		3,362

Middle market lending		—		—		183		183
Other debt obligations		—		15		—		15

Nuclear decommissioning trust fund investments subtotal^(b)		2,782		4,253		183		7,218

Pledged assets for Zion Station decommissioning
Cash equivalents		—		23		—		23
Equity
Equity securities		14		—		—		14
Commingled funds		—		9		—		9

Equity funds subtotal		14		9		—		23

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		118		12		—		130
Debt securities issued by states of the United States and political subdivisions of the states		—		37		—		37
Corporate debt securities		—		249		—		249
Federal agency mortgage-backed securities		—		49		—		49
Commercial mortgage-backed securities (non-agency)		—		6		—		6

Fixed income subtotal		118		353		—		471

Middle market lending		—		—		89		89
Other debt obligations		—		1		—		1

Pledged assets for Zion Station decommissioning subtotal^(c)		132		386		89		607

290

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2012	Level 1			Level 2			Level 3			Total
Rabbi trust investments
Cash equivalents		1			—			—			1
Mutual funds^(d)(e)		13			—			—			13

Rabbi trust investments subtotal		14			—			—			14

Commodity mark-to-market derivative assets
Economic hedges		861			3,173			867			4,901
Proprietary trading		1,042			2,078			73			3,193
Effect of netting and allocation of collateral^(f)		(1,823	)		(4,175	)		(58	)		(6,056	)

Commodity mark-to-market assets subtotal^(g)		80			1,076			882			2,038

Interest Rate mark-to-market derivative assets		—			101			—			101
Effect of netting and allocation of collateral		—			(51	)		—			(51	)

Interest Rate mark-to-market derivative assets subtotal		—			50			—			50

Other investments		2			—			17			19

Total assets		3,497			5,765			1,171			10,433

Liabilities
Commodity mark-to-market derivative liabilities
Economic hedges		(1,041	)		(2,289	)		(169	)		(3,499	)
Proprietary trading		(1,084	)		(1,959	)		(78	)		(3,121	)
Effect of netting and allocation of collateral^(f)		2,042			4,020			25			6,087

Commodity mark-to-market liabilities subtotal		(83	)		(228	)		(222	)		(533	)

Interest rate mark-to-market derivative liabilities		—			(84	)		—			(84	)
Effect of netting and allocation of collateral		—			51			—			51

Interest rate mark-to-market derivative liabilities subtotal		—			(33	)		—			(33	)

Deferred compensation		—			(28	)		—			(28	)

Total liabilities		(83	)		(289	)		(222	)		(594	)

Total net assets	$	3,414		$	5,476		$	949		$	9,839

291

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2011	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents^(a)	$	466	$	—		$	—		$	466
Nuclear decommissioning trust fund investments
Cash equivalents		562		—			—			562
Equity
Equity securities		1,275		—			—			1,275
Commingled funds		—		1,822			—			1,822

Equity funds subtotal		1,275		1,822			—			3,097

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,014		33			—			1,047
Debt securities issued by states of the United States and political subdivisions of the states		—		541			—			541
Debt securities issued by foreign governments		—		16			—			16
Corporate debt securities		—		778			—			778
Federal agency mortgage-backed securities		—		357			—			357
Commercial mortgage-backed securities (non-agency)		—		83			—			83
Residential mortgage-backed securities (non-agency)		—		5			—			5
Mutual funds		—		47			—			47

Fixed income subtotal		1,014		1,860			—			2,874

Middle market lending		—		—			13			13
Other debt obligations		—		18			—			18

Nuclear decommissioning trust fund investments subtotal^(b)		2,851		3,700			13			6,564

Pledged assets for Zion Station decommissioning
Equity
Equity securities		35		—			—			35
Commingled funds		—		30			—			30

Equity funds subtotal		35		30			—			65

Fixed income
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		54		26			—			80
Debt securities issued by states of the United States and political subdivisions of the states		—		65			—			65
Corporate debt securities		—		314			—			314
Federal agency mortgage-backed securities		—		121			—			121
Commercial mortgage-backed securities (non-agency)		—		10			—			10
Commingled funds		—		20			—			20

Fixed income subtotal		54		556			—			610

Middle market lending		—		—			37			37
Other debt obligations		—		13			—			13

Pledged assets for Zion Station decommissioning subtotal^(c)		89		599			37			725

Rabbi trust investments^(d)(e)		4		—			—			4
Commodity mark-to-market derivative assets
Cash flow hedges		—		857			694			1,551
Other derivatives		—		1,653			124			1,777
Proprietary trading		—		240			48			288
Effect of netting and allocation of collateral^(f)		—		(1,827	)		(28	)		(1,855	)

Commodity mark-to-market assets subtotal^(g)		—		923			838			1,761

Total assets		3,410		5,222			888			9,520

292

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2011	Level 1			Level 2			Level 3			Total
Liabilities
Commodity mark-to-market derivative liabilities
Cash flow hedges		—			(13	)		—			(13	)
Other derivatives		(1	)		(1,137	)		(13	)		(1,151	)
Proprietary trading		—			(236	)		(28	)		(264	)
Effect of netting and allocation of collateral^(f)		—			1,295			20			1,315

Commodity mark-to-market liabilities subtotal		(1	)		(91	)		(21	)		(113	)

Interest rate mark-to-market derivative liabilities		—			(19	)		—			(19	)

Deferred compensation		—			(18	)		—			(18	)

Total liabilities		(1	)		(128	)		(21	)		(150	)

Total net assets	$	3,409		$	5,094		$	867		$	9,370

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Excludes net assets (liabilities) of $30 million and $(57) million at December 31, 2012 and December 31, 2011, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(c)	Excludes net assets of $7 million and $9 million at December 31, 2012 December 31, 2011, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d)	The $13 million mutual funds held by the Rabbi trusts are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(e)	Excludes $8 million and $7 million of the cash surrender value of life insurance investments at December 31, 2012 and December 31, 2011, respectively.

(f)

(g)

The Level 3 balance includes current and noncurrent assets for Generation of $226 million and $0 million at December 31, 2012 and $503 million and $191 million at December 31, 2011, respectively, related to the fair value of Generation’s financial swap contract with ComEd, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

293

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2012, and 2011:.


For the Year Ended December 31, 2012	Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Other Investments		Total
Balance as of January 1, 2012	$	13	$	37		$	817			—	$	867
Total unrealized / realized gains (losses)
Included in income		—		—			(112	)^(a)		—		(112	)
Included in other comprehensive income		—		—			(475	)^(b)		—		(475	)
Included in noncurrent payables to affiliates		1		—			—			—		1
Change in collateral		—		—			(32	)		—		(32	)
Purchases, sales, issuances and settlements
Purchases		169		63			334	^(c)		17		583
Sales		—		(11	)		—			—		(11	)
Transfers into Level 3		—		—			39					39
Transfers out of Level 3		—		—			89			—		89

Balance as of December 31, 2012	$	183	$	89		$	660		$	17	$	949

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, 2012	$	—	$	—		$	(12	)	$	—	$	(12	)

(a)	Includes the reclassification of $100 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012.

(b)

Includes $98 million of increases in fair value and realized losses due to settlements of $566 million associated with Generation’s financial swap contract with ComEd for the year ended December 31, 2012. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	Includes $323 million of fair value from contracts and $17 million of other investments acquired as a result of the merger.

294

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2011	Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Total
Balance as of January 1, 2011	$	—	$	—		$	1,030		$	1,030
Total realized / unrealized gains (losses)
Included in income		1		—			99	^(a)		100
Included in other comprehensive income		—		—			(311	)^(b)		(311	)
Included in payable for Zion Station decommissioning		2		—			—			2
Changes in collateral		—		—			6			6
Purchases, sales, issuances and settlements
Purchases		10		60			10			80
Sales		—		(23	)		—			(23	)
Transfers out of Level 3—Liability		—		—			(17	)		(17	)

Balance as of December 31, 2011	$	13	$	37		$	817		$	867

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of December 31, 2011	$	1	$	—		$	131		$	132

(a)	Includes the reclassification of $32 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2011.

(b)

Includes $170 million of increases in fair value and $451 million of realized losses reclassified from OCI due to settlements associated with Generation’s financial swap contract with ComEd for the year ended December 31, 2011, and $5 million of decreases in fair value due to settlement of Generation’s block contracts with PECO for the year ended December 31, 2011. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


	Operating Revenue			Purchased Power and Fuel
Total gains (losses) included in income for the year ended December 31, 2012	$	(146	)	$	34
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2012	$	(25	)	$	13

	Operating Revenue			Purchased Power and Fuel
Total gains (losses) included in income for the year ended December 31, 2011	$	108		$	(8	)
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2011	$	137		$	(5	)

295

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd

The following tables present assets and liabilities 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, 2012 and December 31, 2011:


As of December 31, 2012	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	111	$	—		$	—		$	111
Rabbi trust investments
Mutual funds		8		—			—			8

Rabbi trust investment subtotal		8		—			—			8

Total assets		119		—			—			119

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)
Mark-to-market derivative liabilities^(b)(c)		—		—			(293	)		(293	)

Total liabilities		—		(8	)		(293	)		(301	)

Total net assets (liabilities)	$	119	$	(8	)	$	(293	)	$	(182	)


As of December 31, 2011	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents^(a)	$	173	$	—		$	—		$	173
Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds		19		—			—			19

Rabbi trust investment subtotal		21		—			—			21

Total assets		194		—			—			194

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)
Mark-to-market derivative liabilities ^(b)(c)		—		—			(800	)		(800	)

Total liabilities		—		(8	)		(800	)		(808	)

Total net assets (liabilities)	$	194	$	(8	)	$	(800	)	$	(614	)

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)

The Level 3 balance includes the current and noncurrent liability of $226 million and $0 million at December 31, 2012, respectively, and $503 million and $191 million at December 31, 2011, respectively, related to the fair value of ComEd’s financial swap contract with Generation which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	The Level 3 balance includes the current and noncurrent liability of $18 million and $49 million at December 31, 2012, respectively, and $9 million and $97 million at December 31, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

296

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended and December 31, 2012, and 2011:


For the Year Ended December 31, 2012	Mark-to-Market Derivatives
Balance as of January 1, 2012	$	(800	)
Total realized / unrealized gains included in regulatory assets ^(a)(b)		507

Balance as of December 31, 2012	$	(293	)

(a)	Includes $98 million of decreases in fair value and realized gains due to settlements of $566 million associated with ComEd’s financial swap contract with Generation for the year ended December 31, 2012. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(b)	Includes $34 million of increases in the fair value and realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2012.


Twelve Months Ended December 31, 2011	Mark-to-Market Derivatives
Balance as of January 1, 2011	$	(971	)
Total realized / unrealized gains included in regulatory assets ^(a)(b)		171

Balance as of December 31, 2011	$	(800	)

(a)	Includes $170 million of increases in fair value and $451 million of realized gains due to settlements associated with ComEd’s financial swap contract with Generation for the year ended December 31, 2011. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(b)	Includes $110 million of decreases in fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2011.

PECO

The following tables present 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, 2012 and December 31, 2011:


As of December 31, 2012	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	346	$	—		$	—	$	346
Rabbi trust investments—mutual funds^(b)(c)		9		—			—		9

Total assets		355		—			—		355

Liabilities
Deferred compensation obligation		—		(18	)		—		(18	)

Total liabilities		—		(18	)		—		(18	)

Total net assets (liabilities)	$	355	$	(18	)	$	—	$	337

297

Combined Notes to Consolidated Financial Statements—(Continued)

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


As of December 31, 2011	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	175	$	—		$	—	$	175
Rabbi trust investments—mutual funds ^(b)(c)		9		—			—		9

Total assets		184		—			—		184

Liabilities
Deferred compensation obligation		—		(21	)		—		(21	)

Total liabilities		—		(21	)		—		(21	)

Total net assets (liabilities)	$	184	$	(21	)	$	—	$	163

(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 trusts are classified as Level 1 as they are valued based upon quoted prices (unadjusted) in active markets.

(c)	Excludes $13 million of the cash surrender value of life insurance investments at December 31, 2012 and 2011, respectively.

PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the year ended December 31, 2012.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2011:


Year Ended December 31, 2011	Mark-to-Market Derivatives
Balance as of January 1, 2011	$	(9	)
Total realized gains included in regulatory assets		9	^(a)

Balance as of December 31, 2011	$	—

(a)	Includes an increase of $5 million related to the settlement of PECO’s block contracts with Generation, which eliminates upon consolidation in Exelon’s Consolidated Financial Statements. Generation’s block contracts with PECO expired on December 31, 2011.

298

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE

The following tables present assets and liabilities measured and recorded at fair value on BGE’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2012 and December 31, 2011:


As of December 31, 2012	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	33	$	—		$	—	$	33
Rabbi trust investments—mutual funds		5		—			—		5

Total assets		38		—			—		38

Liabilities
Deferred compensation obligation		—		(5	)		—		(5	)

Total liabilities		—		(5	)		—		(5	)

Total net assets (liabilities)	$	38	$	(5	)	$	—	$	33


As of December 31, 2011	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	33	$	—	$	—	$	33

Total assets		33		—		—		33
Liabilities

Total net assets (liabilities)	$	33	$	—	$	—	$	33

BGE had no Level 3 assets or liabilities measured at fair value on a recurring basis during the year ended December 31, 2012.

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, PECO and BGE). The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables 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 and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s nuclear decommissioning obligations as required by the NRC. 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 limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. 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.

299

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 from pricing services are obtained 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. 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 or similar securities, adjusted for observable differences and are categorized in Level 2.

Equity and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual 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 equity 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 and mutual funds are categorized in Level 2 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 on the underlying equity securities.

Middle market lending are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE). 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 investments are in fixed-income commingled funds and mutual funds, including short-term investment funds. These funds are maintained by investment companies and hold certain investments in accordance with a stated set of

300

Combined Notes to Consolidated Financial Statements—(Continued)

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

fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For fixed-income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Fixed-income commingled funds and mutual funds which are publicly quoted, such as money market funds, have been categorized as Level 1 given the clear observability of the prices.

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’ pricing is verified using indicative price quotations 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. Such instruments are categorized in Level 3.

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. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market’s expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. 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 10—Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). 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.

301

Combined Notes to Consolidated Financial Statements—(Continued)

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

Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd)

Mark-to-Market Derivatives (Exelon, Generation, ComEd). 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. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. 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. 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, corporate controller, 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 and is responsible for approving all valuation procedures at Exelon. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements. Transfers in and out of levels are recognized as of the end of the reporting period the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 generally do not occur. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable. Transfers into Level 3 from Level 2 generally occur due to changes in market liquidity or assumptions for certain commodity contracts.

Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The most significant position is the long term intercompany swap with ComEd, which is further discussed in Note 10—Derivative Financial Instruments. The calculated fair value includes marketability discounts for margining provisions and notional size. Generation’s remaining Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, transmission congestion contracts, and project financing debt. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and

302

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation’s own credit quality for liabilities. The level of observability of a forward commodity price is generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are highly liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instruments market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is generally less than $4 and $.25 for power and natural gas respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3.—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrant’s mark-to-market derivative assets and liabilities.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 10—Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. The table below discloses the significant inputs to the forward curve used to value these positions.


Type of trade	Fair Value at December 31, 2012 ^(d)			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic Hedges (Generation) ^(a)	$	473		Discounted Cash Flow	Forward power price	$14 - $79
					Forward gas price Volatility	$3.26 - $6.27
				Option Model	percentage	28% - 132%

Mark-to-market derivatives—Proprietary trading (Generation) ^(a)	$	(6	)	Discounted Cash Flow	Forward power price Volatility	$15 - $106
				Option Model	percentage	16% - 48%

Mark-to-market derivatives—Transactions with affiliates (Generation and ComEd) ^(b)	$	226		Discounted Cash Flow	Marketability reserve	8% - 9%

Mark-to-market derivatives (ComEd)	$	(67	)	Discounted Cash Flow	Forward heat rate^(c)	8% - 9.5%
					Marketability reserve	3.5% - 8.3%
					Renewable factor	81% - 123%

303

Combined Notes to Consolidated Financial Statements—(Continued)

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

a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

b)	Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd, which eliminates in consolidation.

c)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

d)	The fair values do not include cash collateral held on Level 3 positions of $33 million as of December 31, 2012.

The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). For middle market lending the fair value of these loans is determined using a combination of valuations models including cost models, market models and income models. The valuation estimates are based on valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the applications of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability and relative performance.

Because Generation relies on third party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its’ middle market lending, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its’ middle market lending, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.

10. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)

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.

Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)

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

304

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, effective with the date of merger with Constellation, Generation will no longer utilize the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation’s designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivative economic hedges for commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 19—Commitments and Contingencies. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

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, natural gas transportation and pipeline capacity agreements 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

305

Combined Notes to Consolidated Financial Statements—(Continued)

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

derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2012, the percentage of expected generation hedged for the major reportable segments was 94%-97%, 62%-65% and 27%-30% for 2013, 2014, and 2015, 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 economic hedges and certain non-derivative contracts including, sales to ComEd, PECO and BGE 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 process, which are further discussed in Note 3—Regulatory Matters, qualify for the NPNS 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 Legislation, 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 load service requirements. The remaining swap contract volume is 3,000 MWs through May 2013. The terms of the financial swap contract require Generation to pay the around-the-clock 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 was originally designated by Generation as a cash flow hedge. As discussed previously, effective with the date of merger with Constellation, Generation de-designated this swap as a cash flow hedge and began recording changes in fair value through current earnings as of that date. Generation records the fair value of the swap on its balance sheet and originally recorded changes in fair value to OCI. The value frozen in OCI as of the date of merger for this swap is reclassified into Generation’s earnings as the swap settles. ComEd has not elected hedge accounting for this derivative financial instrument. Since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and, therefore, the change in fair value each period is recorded as a regulatory asset or liability on ComEd’s Consolidated Balance Sheets. See Note 3—Regulatory Matters for additional information regarding the Illinois Settlement Legislation. In Exelon’s consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated.

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge

306

Combined Notes to Consolidated Financial Statements—(Continued)

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

accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 3—Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs 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 is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO’s full requirements contracts and block contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. For block contracts designated as normal purchases after inception, the mark-to-market balances previously recorded on PECO’s Consolidated Balance Sheet were amortized over the terms of the contracts, which ended on December 31, 2011.

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 delivery 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 asset management agreements that are derivatives either qualify for the normal purchases and normal sales scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2012 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 2012 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 is designed to cover about 30% 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.

BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its Standard Offer Service requirements through full requirements contracts. BGE’s full requirements contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance.

BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing

307

Combined Notes to Consolidated Financial Statements—(Continued)

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

(i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the normal purchases and normal sales exception and result in physical delivery.

Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 12,958 GWh, 5,742 GWh and 3,625 Gwh for the years ended December 31, 2012, 2011 and 2010, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes.

Interest Rate Risk (Exelon, Generation, ComEd, PECO and BGE)

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 rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2012, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and $452 million of notional amounts of pre-issuance hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper and PECO Accounts Receivables Facility) and fixed-to-floating swaps would result in less than $2 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2012. Below is a summary of the interest rate hedges as of December 31, 2012.


	Generation															Other		Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading ^(a)			Collateral and Netting ^(b)			Subtotal			Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (Current Assets)	$	—		$	3		$	20		$	(19	)	$	4		$	—	$	4
Mark-to-market derivative assets (Noncurrent Assets)		38		$	8		$	32			(32	)		46			13		59

Total mark-to-market derivative assets	$	38		$	11		$	52		$	(51	)	$	50		$	13	$	63

Mark-to-market derivative liabilities (Current Liabilities)	$	(1	)	$	(1	)	$	(19	)	$	19		$	(2	)	$	—	$	(2	)
Mark-to-market derivative liabilities (Noncurrent Liabilities)		(31	)	$	—		$	(32	)		32			(31	)		—		(31	)

Total mark-to-market derivative liabilities	$	(32	)	$	(1	)	$	(51	)	$	51		$	(33	)	$	—	$	(33	)

Total mark-to-market derivative net assets (liabilities)	$	6		$	10		$	1		$	—		$	17		$	13	$	30

308

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

(b)	Represents the netting of fair value balances with the same counterparty and collateral.

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:


	Gain (Loss) on Swaps							Gain (Loss) on Borrowings
	Twelve Months Ended December 31,							Twelve Months Ended December 31,
Income Statement Classification	2012			2011		2010		2012			2011			2010
Interest expense ^(a)	$	(6	)	$	1	$	4	$	(6	)	$	(1	)	$	(4	)

(a)	For the year ended December 31, 2012, the loss on the swaps in the table above includes $12 million reclassified to earnings, with an immaterial amount excluded from hedge effectiveness testing.

At December 31, 2012, and December 31, 2011, Exelon had $650 million and $100 million, respectively, of notional amounts of fixed-to-floating fair value hedges outstanding related to interest rate swaps, with unrealized gain of $49 million and $15 million, respectively, which expire in 2015. Upon merger closing, $550 million of fixed-to-floating interest rate swaps previously at Constellation with a fair value of $44 million, as of March 12, 2012, were re-designated as fair value hedges. During the years ended December 31, 2012, and December 31, 2011, the impact on the results of operations as a result of ineffectiveness from fair value hedges was immaterial.

Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley acquisition, as discussed in Note 11—Debt and Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of April 5, 2014, by which date Generation anticipates the DOE loan to be fully drawn. The swap hedges approximately 75% of Generation’s future interest rate exposure associated with the financing and was designated as a cash flow hedge. As such, the effective portion of the hedge will be recorded in other comprehensive income within Generation’s Consolidated Balance Sheets, with any ineffectiveness recorded in Generation’s Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, will be amortized as an adjustment to the interest expense over the term of the DOE guaranteed loan.

As Generation draws down on the loan, a portion of the cash flow hedge will be de-designated and the related gains or losses going forward will be reflected in earnings. In order to mitigate this earnings impact, a series of offsetting hedge transactions are executed as Generation draws on the loan.

Antelope Valley received its first loan advance on April 5, 2012, and several additional advances subsequently, as described in Note 11—Debt and Credit Agreements. Generation has entered into a series of fixed-to-floating interest rate swaps with an aggregated notional amount of $165 million, 75% of the loan advance amount to offset portions of the original interest rate hedge, which are de-designated as cash flow hedges. The remaining cash flow hedge has a notional amount of

309

Combined Notes to Consolidated Financial Statements—(Continued)

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

$320 million. At December 31, 2012, Generation’s mark-to-market non-current derivative liability relating to the interest rate swap in connection with the loan agreement to fund Antelope Valley was $28 million.

During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Sacramento PV Energy. The swaps have a total notional amount of $29 million as of December 31, 2012 and expire in 2027. After the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At December 31, 2012, the subsidiary had a $4 million non-current derivative liability related to these swaps.

During the third quarter of 2012, a subsidiary of Exelon Generation entered into a floating-to-fixed forward starting interest rate swap to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Constellation Solar Horizons. The swap has a notional amount of $29 million as of December 31, 2012 and expires in 2030. This swap is designated as a cash flow hedge. At December 31, 2012, the subsidiary had an immaterial non-current derivative liability related to the swap.

During the third quarter of 2012, Exelon entered into $75 million floating-to-fixed forward starting interest rate hedges to manage interest rate risks associated with anticipated future debt issuance. These swaps are designated as cash flow hedges. At December 31, 2012, there is $1 million non-current derivative asset related to these swaps.

During the years ended December 31, 2012, and 2011, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.

Economic Hedges. At December 31, 2012, Exelon had $150 million of notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with an unrealized gain of $5 million. These swaps, which were acquired as part of the merger with Constellation, expire in 2014. During the period from March 12 to December 31, 2012, the impact on the results of operations was immaterial.

Fair Value Measurement (Exelon, Generation, ComEd, PECO and BGE)

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 energy related cash flow hedges, economic hedges, 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 NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

310

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 the Registrants as of December 31, 2012:


	Generation												ComEd						Exelon
Derivatives	Economic Hedges ^(a)			Proprietary Trading			Collateral and Netting ^(b)			Subtotal ^(c)			Economic Hedges ^(a)(d)			Intercompany Eliminations ^(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	2,883		$	2,469		$	(4,418	)	$	934		$	—		$	—		$	934
Mark-to-market derivative assets with affiliate (current assets)		226			—			—			226			—			(226	)		—
Mark-to-market derivative assets (noncurrent assets)		1,792			724			(1,638	)		878			—			—			878

Total mark-to-market derivative assets	$	4,901		$	3,193		$	(6,056	)	$	2,038		$	—		$	(226	)	$	1,812

Mark-to-market derivative liabilities (current liabilities)	$	(2,419	)	$	(2,432	)	$	4,519		$	(332	)	$	(18	)	$	—		$	(350	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			(226	)		226			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(1,080	)		(689	)		1,568			(201	)		(49	)		—			(250	)

Total mark-to-market derivative liabilities	$	(3,499	)	$	(3,121	)	$	6,087		$	(533	)	$	(293	)	$	226		$	(600	)

Total mark-to-market derivative net assets (liabilities)	$	1,402		$	72		$	31		$	1,505		$	(293	)	$	—		$	1,212

(a)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation, excludes $28 million non current liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above.

(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 $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(214) million and $(131) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $31 million at December 31, 2012.

(d)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

311

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 the Registrants as of December 31, 2011:


	Generation															ComEd			Other					Exelon
Derivatives	Cash Flow Hedges ^(a)			Economic Hedges			Proprietary Trading			Collateral and Netting ^(b)			Subtotal ^(c)			Economic Hedges ^(a)(d)			Economic Hedges		Intercompany Eliminations ^(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	438		$	1,195		$	217		$	(1,418	)	$	432		$	—		$	—	$	—		$	432
Mark-to-market derivative assets with affiliate (current assets)		503			—			—			—			503			—			—		(503	)		—
Mark-to-market derivative assets (noncurrent assets)		419			582			71			(437	)		635			—			15		—			650
Mark-to-market derivative assets with affiliate (noncurrent assets)		191			—			—			—			191			—			—		(191	)		—

Total mark-to-market derivative assets	$	1,551		$	1,777		$	288		$	(1,855	)	$	1,761		$	—		$	15	$	(694	)	$	1,082

Mark-to-market derivative liabilities (current liabilities)	$	(9	)	$	(965	)	$	(194	)	$	1,065		$	(103	)	$	(9	)	$	—	$	—		$	(112	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(503	)		—		503			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(4	)		(186	)		(70	)		250			(10	)		(97	)		—		—			(107	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(191	)		—		191			—

Total mark-to-market derivative liabilities	$	(13	)	$	(1,151	)	$	(264	)	$	1,315		$	(113	)	$	(800	)	$	—	$	694		$	(219	)

Total mark-to-market derivative net assets (liabilities)	$	1,538		$	626		$	24		$	(540	)	$	1,648		$	(800	)	$	15	$	—		$	863

(a)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $503 million and $191 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation, excludes $19 million non current liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above.

(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 $338 million and $187 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $15 million and $0 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $540 million at December 31, 2011.

(d)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Cash Flow Hedges (Exelon, Generation and ComEd). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. As discussed previously, effective prior to the merger with Constellation, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation began recording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. The net unrealized gains associated with the de-designated cash flow hedges prior to the merger was $1,928 million including $693 million related to the

312

Combined Notes to Consolidated Financial Statements—(Continued)

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

intercompany swap with ComEd. Approximately $684 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 $219 million related to the financial swap with ComEd. Generation expects the settlement of the majority of its cash flow hedges, including the ComEd financial swap contract, will occur during 2013 through 2014.

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 or when it is no longer probable that the forecasted transaction will occur. For the years ended December 31, 2012 and 2011, 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 years ended December 31, 2012 and 2011, 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 at January 1, 2011			$	1,011	^(a)(d)	$	400
Effective portion of changes in fair value				504	^(b)		402	^(e)
Reclassifications from accumulated OCI to net income		Operating Revenues		(585	)^(c)		(309	)
Ineffective portion recognized in income		Purchased Power		(5	)		(5	)

Accumulated OCI derivative gain at December 31, 2011				925	^(a)(d)		488
Effective portion of changes in fair value				432	^(b)		330	^(e)
Reclassifications from accumulated OCI to net income		Operating Revenues		(828	)^(c)		(453	)
Ineffective portion recognized in income		Operating Revenues		3			3

Accumulated OCI derivative gain at December 31, 2012			$	532	^(a)(d)	$	368

(a)

Includes $133 million, $420 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012, 2011 and 2010, respectively, and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO for the year ended December 31, 2010.

(b)

Includes $88 million and $104 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011, respectively, and $2 million of gains, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the year ended December 31, 2010. As of the merger date, cash flow hedges were discontinued, as such, this amount represents changes in fair value prior to the merger date.

(c)

Includes $375 million and $273 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011, respectively, and $3 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the block contracts with PECO for the year ended December 31, 2011.

313

Combined Notes to Consolidated Financial Statements—(Continued)

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

(d)	Excludes $20 million of losses and $10 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2012 and 2011, respectively.

(e)	Includes $9 million and $12 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the year ended December 31, 2012 and 2011, respectively.

During the years ended December 31, 2012, 2011, and 2010 Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $1,368 million, $968 million and $1,125 million pre-tax gain, respectively. Given that the cash flow hedges had primarily consisted of forward power sales and power swaps and did not include power and gas options or sales, the ineffectiveness of Generation’s cash flow hedges was primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference was 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 losses of $5 million and gains of $10 million and $1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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 $747 million pre-tax gain for the year ended December 31, 2012, and a $512 million and $754 million pre-tax gain for the years ended 2011 and 2010, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were losses of $5 million and gains of $10 million and $1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Neither Exelon nor Generation will not incur changes in cash flow hedge ineffectiveness in future periods as all commodity cash flow hedge positions were de-designated prior to the merger date.

Economic Hedges (Exelon and Generation). These instruments represent hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and physical forward sales and purchases. For the years ended December 31, 2012, 2011 and 2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues or purchased power and fuel expense at Exelon and Generation in the 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 3rd quarter of 2012, Generation completed a non-cash exchange by issuing a new in-the-money derivative with a new counterparty in exchange for novating to them existing in-the-money trades with the old counterparty for a total of $51 million. This transaction did not have any Income Statement effect to Generation. 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.


	Generation								Intercompany Eliminations			Exelon
Year Ended December 31, 2012	Operating Revenues			Purchased Power and Fuel		Total			Operating Revenues^(a)			Total
Change in fair value	$	(362	)	$	215	$	(147	)	$	(94	)	$	(241	)
Reclassification to realized at settlement		429			238		667			101			768

Net mark-to-market gains (losses)	$	67		$	453	$	520		$	7		$	527

314

Combined Notes to Consolidated Financial Statements—(Continued)

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


Year Ended December 31, 2011 (As Reported)	Operating Revenues			Purchased Power and Fuel			Total
Change in fair value	$	87		$	131		$	218
Reclassification to realized at settlement		(296	)		(219	)		(515	)

Net mark-to-market (losses)^(b)	$	(209	)	$	(88	)	$	(297	)


	Exelon and Generation
Year Ended December 31, 2011 (Pro Forma)	Operating Revenues			Purchased Power and Fuel			Total
Change in fair value	$	258		$	(40	)	$	218
Reclassification to realized at settlement		(516	)		1			(515	)

Net mark-to-market (losses)^(b)	$	(258	)	$	(39	)	$	(297	)


	Exelon and Generation
Year Ended December 31, 2010 (As Reported)	Operating Revenues			Purchased Power and Fuel			Total
Change in fair value	$	—		$	389		$	389
Reclassification to realized at settlement		—			(304	)		(304	)

Net mark-to-market (losses)^(b)	$	—		$	85		$	85

(a)	Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation.

(b)

Exelon and Generation have historically presented mark-to-market gains and losses within purchased power expense for all non-trading, energy-related derivatives that were not accounted for as cash flow hedges. In 2011, Exelon and Generation classified the mark-to-market gains and losses for contracts, where the underlying hedged transaction was an expected sale to hedge power, to operating revenues.

Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2012, and 2011, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on derivative instruments entered into for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as operating 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 Years Ended December 31,
	Location on Income Statement		2012			2011			2010
Change in fair value		Operating Revenue	$	(12	)	$	23		$	26
Reclassification to realized at settlement		Operating Revenue		108			(26	)		(24	)

Net mark-to-market gains		Operating Revenue	$	96		$	(3	)	$	2

315

Combined Notes to Consolidated Financial Statements—(Continued)

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

Credit Risk (Exelon, Generation, ComEd, PECO and BGE)

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 by credit rating agencies, 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, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2012. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through exchanges (i.e. NYMEX, ICE), further discussed in ITEM 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and BGE of $54 million, $56 million and $31 million, respectively.


Rating as of December 31, 2012	Total Exposure Before Credit Collateral		Credit Collateral ^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure		Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,984	$	347	$	1,637		1	$	262
Non-investment grade		28		24		4		—		—
No external ratings
Internally rated—investment grade		512		10		502		1		271
Internally rated—non-investment grade		41		3		38		—		—

Total	$	2,565	$	384	$	2,181		2	$	533


Net Credit Exposure by Type of Counterparty	December 31, 2012
Investor-owned utilities, marketers and power producers	$	865
Energy cooperatives and municipalities		786
Financial Institutions		422
Other		108

Total	$	2,181

316

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	As of December 31, 2012, credit collateral held from counterparties where Generation had credit exposure included $344 million of cash and $40 million of letters of credit.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2012, ComEd’s credit exposure to suppliers was immaterial.

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 3—Regulatory Matters for further information.

PECO’s supplier master agreements that govern the terms of its electric supply procurement 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 the major credit rating agencies 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, 2012, PECO had no net credit exposure with suppliers.

PECO is permitted to recover its costs of procuring electric supply 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 3—Regulatory Matters 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 asset 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 asset management agreements; however, the natural gas asset managers have provided $20 million in parental guarantees related to these agreements. As of December 31, 2012, PECO had credit exposure of $7 million under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters for further information.

317

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. The seller’s credit exposure is calculated each business day. As of December 31, 2012, BGE had no net credit exposure with suppliers.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE)

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. 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. 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. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


Credit-Risk Related Contingent Feature		December 31, 2012
Gross Fair Value of Derivative Contracts Containing this Feature ^(a)	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements ^(b)	Net Fair Value of Derivative Contracts Containing This Feature ^(c)
($1,849)	$1,426	($423)

Credit-Risk Related Contingent Feature		December 31, 2011
Gross Fair Value of Derivative Contracts Containing this Feature ^(a)	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements ^(b)	Net Fair Value of Derivative Contracts Containing This Feature ^(c)
($1,014)	$928	($86)

318

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements.

(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.

(c)

Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Generation has cash collateral posted of $527 million and letters of credit posted of $563 million and cash collateral held of $499 million and letters of credit held of $45 million as of December 31, 2012 and cash collateral held of $542 million and letters of credit held of $89 million at December 31, 2011. In the event of a credit downgrade below investment grade (i.e. BB+ or Ba1), Exelon Generation Company, LLC and Constellation Energy Commodities Group, Inc. could be required to post additional collateral of $1,920 million as of December 31, 2012, and $1,612 million as of December 31, 2011. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if their debt ratings were to materially weaken, 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, 2012, Generation’s and Exelon’s swaps were in an asset position, with a fair value of $17 million and $30 million, respectively.

See Note 21—Segment Information for further information regarding the letters of credit supporting the cash collateral.

Generation entered into SFCs with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of the 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 contract, collateral postings will never exceed $200 million from either ComEd or Generation. 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, 2012, ComEd held neither cash nor letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of December 31, 2012, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 1—Significant Accounting Policies for further information.

319

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2012, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2012, PECO could have been required to post approximately $35 million of collateral to its counterparties.

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.

BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2012, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2012, BGE could have been required to post approximately $124 million of collateral to its counterparties.

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

As of December 31, 2012, and December 31, 2011, $3 million and $2 million, respectively, of cash collateral received was not offset against derivative positions because they were not associated with energy-related derivatives.

11. Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE)

Short-Term Borrowings

Exelon, ComEd and BGE meet their 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.

Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2012 and 2011:


	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer	2012 ^(a)		2011 ^(a)		2012		2011		2012			2011
Exelon Corporate	$	500	$	500	$	—	$	161		0.47	%		0.42	%
Generation		5,600		5,600		—		—		0.45	%		0.48	%
ComEd		1,000		1,000		—		—		0.50	%		0.71	%
PECO		600		600		—		—		—			—
BGE		600		400		—		—		0.43	%		0.38	%

Total	$	8,300	$	8,100	$	—	$	161

(a)	Equals aggregate bank commitments under revolving and bilateral credit agreements. See discussion below and Credit Agreements table below for items affecting effective program size.

320

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 outstanding commercial paper does not reduce available capacity under a Registrant’s credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit agreement.

At December 31, 2012, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements:



							Available Capacity at December 31, 2012
Borrower	Aggregate Bank Commitment ^(a)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper
Exelon Corporate	$	500	$	—	$	2	$	498	$	498
Generation		5,600		—		1,818		3,782		3,782
ComEd		1,000		—		—		1,000		1,000
PECO		600		—		1		599		599
BGE		600		—		—		600		600

Total	$	8,300	$	—	$	1,821	$	6,479	$	6,479

(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 19, 2013 and are solely for issuing letters of credit. As of December 31, 2012, letters of credit issued under these agreements totaled $23 million, $21 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively.

For the year ended December 31, 2012, there were no borrowings under the Registrants’ credit facilities.

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, and BGE during 2012, 2011 and 2010. PECO did not have any short-term borrowings outstanding during 2012, 2011 or 2010.

Exelon


	2012			2011			2010
Average borrowings	$	199		$	218		$	125
Maximum borrowings outstanding		505			600			346
Average interest rates, computed on a daily basis		0.48	%		0.50	%		0.72	%
Average interest rates, at December 31		n.a.			0.44	%		n.a.

*Generation*

	2012			2011			2010
Average borrowings	$	4		$	51		$	—
Maximum borrowings outstanding		165			304			—
Average interest rates, computed on a daily basis		0.45	%		0.48	%		n.a.
Average interest rates, at December 31		n.a.			n.a.			n.a.

321

Combined Notes to Consolidated Financial Statements—(Continued)

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


*ComEd*

	2012			2011			2010
Average borrowings	$	110		$	36		$	125
Maximum borrowings outstanding		366			407			346
Average interest rates, computed on a daily basis		0.50	%		0.71	%		0.72	%
Average interest rates, at December 31		n.a.			n.a.			n.a.

*BGE*

	2012			2011			2010
Average borrowings	$	6		$	26		$	1
Maximum borrowings outstanding		76			190			46
Average interest rates, computed on a daily basis		0.43	%		0.38	%		0.39	%
Average interest rates, computed at December 31		n.a.			n.a.			n.a.

n.a.	Not applicable.

Credit Agreements

In connection with the Upstream Merger, Exelon assumed all of Constellation’s obligations under its three-year, unsecured revolving credit facility (the “Constellation Credit Agreement”). Effective as of the Initial Merger, the Constellation Credit Agreement was amended and restated to (1) permit Exelon and Constellation to consummate the Upstream Merger and the restructuring transaction, (2) reduce the aggregate commitments under the Constellation Credit Agreement from $2.5 billion to $1.5 billion, and (3) conform some of the representations, warranties, covenants and events of default in the Constellation Credit Agreement with representations, warranties, covenants and events of default in the Exelon credit agreement, dated as of March 23, 2011, as amended as of the Initial Merger. In connection with the Upstream Merger, Exelon also assumed Constellation’s obligations under four separate bilateral credit facilities and a commodity-linked credit facility, which were also amended to conform with the Constellation Credit Agreement effective as of the Initial Merger. Effective as of the Initial Merger, the Exelon Credit Agreement and the Generation Credit Agreement were amended and restated to conform some of the representations, warranties and covenants with provisions of the Constellation Credit Agreement, as amended effective as of the Initial Merger. Exelon Corporation (as successor to Constellation Energy Group) entered into an amendment to the Amended and Restated Credit Agreement dated March 12, 2012, which changed the maturity date to December 31, 2012. See Note 4—Merger and Acquisitions for further description of the merger transaction.

On August 10, 2012, Exelon Corporate, Generation, PECO and BGE amended and extended their respective unsecured syndicated revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, through August 10, 2017. Under these facilities, Exelon Corporate, Generation, PECO and BGE may issue letters of credit in the aggregate of up to $200 million, $3.5 billion, $300 million and $600 million, respectively. Each credit facility permits the applicable borrower to request extensions for up to two additional one-year periods. Each credit facility also allows Exelon Corporate, Generation, PECO and BGE to request increases in aggregate commitments up to an additional $250 million, $1.0 billion, $250 million and $100 million, respectively. Any extension or increase of a credit facility is subject to the approval of the lenders party to that credit facility in their sole discretion. Costs incurred to amend and extend the facilities for Exelon Corporate, Generation, PECO and BGE were not material.

322

Combined Notes to Consolidated Financial Statements—(Continued)

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

On March 28, 2012, ComEd replaced its unsecured revolving credit facility with a new unsecured facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement has an initial term expiring on March 28, 2017, and ComEd may request up to two, one-year extensions of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to replace the credit facility for ComEd were not material.

Borrowings under each credit agreement bear interest at a rate selected by the borrower based upon the prime rate or at a fixed rate for a specified period based upon a LIBOR-based rate. As of December 31, 2012, Exelon Corporate, Generation, PECO and BGE have adders of up to 27.5, 7.5, 0.0 and 7.5 basis points for prime based borrowings and 127.5, 107.5, 100.0 and 107.5 basis points for LIBOR-based borrowings, respectively. The fee varies depending upon the respective credit ratings of each entity. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The amended covenants in the amended credit facilities are substantially consistent with the covenants in the prior facilities, with the exception of BGE, which replaced its debt to capitalization covenant with an interest coverage ratio.

On October 19, 2012, Generation, ComEd and PECO replaced their expiring minority and community bank credit facilities with new minority and community bank credit facility agreements in the amounts of $50 million, $34 million and $34 million, respectively, and BGE entered into a minority and community bank credit facility in the amount of $5 million. These facilities, which expire in October 2013, are solely utilized by the applicable Registrants to issue letters of credit.

On January 23, 2013, Generation entered into a two year $75 million bilateral letter of credit facility with a bank. This facility will solely be utilized by Generation to issue letters of credit.

An event of default under any of the Registrants’ credit facilities would 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 would constitute an event of default under the Exelon corporate credit facility.

Each credit facility 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, 2012:

Exelon

Generation

ComEd

PECO

BGE

Credit facility threshold

2.50 to 1

3.00 to 1

2.00 to 1

At December 31, 2012, the interest coverage ratios at the Registrants were as follows:


	Exelon		Generation		ComEd		PECO		BGE
Interest coverage ratio		9.62		14.20		6.14		7.85		5.16

323

Combined Notes to Consolidated Financial Statements—(Continued)

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

Accounts Receivable Agreement

PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its accounts receivable designated under the agreement in exchange for proceeds of $225 million. As of December 31, 2012 and 2011, the financial institution’s undivided interest in PECO’s gross accounts receivable was equivalent to $289 million and $329 million, respectively, which represents the financial institution’s interest in PECO’s eligible receivables as calculated under the terms of the agreement. The agreement requires PECO to maintain eligible receivables at least equivalent to the financial institution’s undivided interest. Upon termination or liquidation of this agreement, the financial institution is entitled to recover up to $225 million plus the accrued yield payable from its undivided interest in PECO’s receivables. On August 31, 2012, PECO entered into an Amendment to extend this agreement until August 30, 2013. This Amendment also expands the definition of a tariff receivable to include receivables that have been purchased by PECO and paid for in accordance with the Tariff and revises the compliance criteria for the eligible asset test to allow for the payment of capital within a specified period of time. On November 28, 2012, PECO made a principal paydown of $15 million to meet the eligible asset test requirement of the agreement for the October 2012 reporting period. The remaining principal balance of $210 million is classified as a short-term note payable on Exelon’s and PECO’s Consolidated Balance Sheets. As of December 31, 2012, PECO was in compliance with the requirements of the agreement. In the event the agreement is not further extended, PECO has sufficient short-term liquidity and may seek alternate financing.

Long-Term Debt

On June 18, 2012, Generation issued and sold $775 million of Senior Notes. In connection with this debt issuance, Generation entered into forward-starting interest rate swaps in the aggregate notional amount of $470 million. The interest rate swaps were settled on June 15, 2012 with Generation recording a pre-tax loss of approximately $7 million. The loss was recorded to other comprehensive income within Exelon’s and Generation’s Consolidated Balance Sheets and is being amortized to income over the life of the related debt as an increase to interest expense.

Concurrently with the new debt issuance, Generation engaged in private offers (the Exchange Offer) to certain eligible holders to exchange any and all of the $700 million outstanding 7.60% Senior Notes due 2032 (Old Notes) of Exelon (which were assumed by Exelon in the merger with Constellation), for:

•

Generation’s newly issued 4.25% Senior Notes due 2022, plus a cash payment; and

•

Generation’s newly issued 5.60% Senior Notes due 2042, plus a cash payment.

On June 28, 2012, pursuant to the Exchange Offer, Generation purchased $441 million of the Old Notes in exchange for issuing $535 million of Notes due in 2022 and 2042, plus a cash payment of approximately $60 million. The $441 million of Old Notes were recorded on Exelon’s Consolidated Balance Sheets at $608 million, reflecting a fair value adjustment pursuant to the application of purchase accounting applied as a result of the Constellation merger which resulted in approximately $13 million gain from the Exchange Offer at Generation. The gain was recorded as an increase to Long-term Debt within Exelon’s and Generation’s Consolidated Balance Sheets and will be amortized to income over the life of the debt as a reduction in interest expense.

On July 13, 2012, pursuant to the Exchange Offer described above, Generation purchased an additional $1 million of Old Notes in exchange for the Senior Notes due in 2022 and 2042.

324

Combined Notes to Consolidated Financial Statements—(Continued)

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

In connection with the debt obligations assumed by Exelon as part of the Upstream Merger on March 12, 2012, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. The third-party debt obligations are reported in Long-term Debt on Exelon’s Consolidated Balance Sheets. The intercompany loan agreements are summarized as follows:

•

$700 million aggregate principal amount of Old Notes, $258 million of which was outstanding as of December 31, 2012 after the Exchange Offer described above;

•

$550 million aggregate principal amount of 4.55% Fixed-Rate Notes due 2015, all of which was outstanding as of December 31, 2012;

•

$450 million aggregate principal amount of 8.625% Series A Junior Subordinated Debentures due 2063, all of which was outstanding as of December 31, 2012; and

•

$550 million aggregate principal amount of 5.15% Notes due 2020, all of which was outstanding as of December 31, 2012.

The intercompany loan agreements and the third-party debt obligations described above were increased by $403 million for a fair value adjustment pursuant to the application of purchase accounting applied as a result of the Constellation merger, of which $199 million was outstanding as of December 31, 2012, primarily reflecting the Exchange Offer described above and amortization of purchase accounting adjustment, which is being amortized over the lives of the arrangements as a reduction to interest expense.

In November 2012, Generation filed a registration statement on Form S-4 to register senior notes to be issued in connection with an exchange offer for the senior notes that were privately issued in June and July 2012. The exchange offer was consummated on February 19, 2013. The registered notes have the same terms and maturity dates as the privately placed senior notes.

325

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2012 and 2011:

Exelon


				Maturity Date		December 31,
	Rates			Maturity Date		2012			2011
Long-term debt
First Mortgage Bonds ^(a) (b):
Fixed rates		1.63% — 7.63%			2012-2042	$	7,397		$	7,522
Unsecured bonds:		2.80% — 6.35%			2013-2036		1,850			—
Rate stabilization bonds:		5.72% — 5.82%			2017		332			—
Senior unsecured notes		2.00% — 8.63%			2014-2063		8,021			4,902
Notes payable and other ^(c)		6.95% — 7.83%			2012-2020		177			174
Pollution control notes:
Fixed rates		4.10% — 5.00%			2014-2042		20			46
Non-recourse debt:
Fixed rates		2.33% — 5.50%			2031-2037		238			—
Variable rates		1.96% — 2.77%			2014-2030		262			—

Total long-term debt							18,297			12,644
Unamortized debt discount and premium, net							(17	)		(32	)
Fair value adjustment							448			—
Fair value hedge carrying value adjustment, net							17			15
Long-term debt due within one year							(1,047	)		(828	)

Long-term debt						$	17,698		$	11,799

Long-term debt to financing trusts ^(d)
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
Subordinated debentures to BGE Trust		6.20	%		2043		258			—

Total long-term debt to financing trusts						$	648		$	390

(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 $30 million and $34 million at December 31, 2012 and 2011, respectively. Lease payments of $3 million, $3 million, $3 million, $4 million, $4 million and $13 million will be made in 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.

(d)	Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon’s Consolidated Balance Sheets.

326

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation


			Maturity Date		December 31,
	Rates		Maturity Date		2012			2011
Long-term debt
Senior unsecured notes ^(b)		2.00% — 8.63%		2014-2063	$	6,721		$	3,602
Pollution control notes:
Fixed rates		4.10% — 5.00%		2014-2042		20			46
Non-recourse debt:
Fixed rates		2.33% — 5.50%		2031-2037		238			—
Variable rates		1.96% — 2.77%		2014-2030		262			—
Notes payable and other ^(a)		7.83%		2012-2020		30			34

Total long-term debt						7,271			3,682
Fair value adjustment ^(b)						199			—
Unamortized debt discount and premium, net						13			(5	)
Long-term debt due within one year						(28	)		(3	)

Long-term debt					$	7,455		$	3,674

(a)	Includes Generation’s capital lease obligations of $30 million and $34 million at December 31, 2012 and 2011, respectively. Generation will make lease payments of $3 million, $3 million, $3 million, $4 million, $4 million and $13 million in 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.

(b)	Includes $2,007 million of long-term debt to affiliate, comprised of $1,808 million senior unsecured notes and $199 million fair value adjustment.

ComEd


				Maturity Date		December 31,
	Rates			Maturity Date		2012			2011
Long-term debt
First Mortgage Bonds ^(a) (b):
Fixed rates		1.63% — 7.63%			2012-2042	$	5,447		$	5,547
Notes payable		6.95	%		2018		140			140

Total long-term debt							5,587			5,687
Unamortized debt discount and premium, net							(20	)		(22	)
Long-term debt due within one year							(252	)		(450	)

Long-term debt						$	5,315		$	5,215

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.

327

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO


			Maturity Date		December 31,
	Rates		Maturity Date		2012			2011
Long-term debt
First Mortgage Bonds ^(a) (b):
Fixed rates		2.38% — 5.95%		2012-2037	$	1,950		$	1,975

Total long-term debt						1,950			1,975
Unamortized debt discount and premium, net						(3	)		(3	)
Long-term debt due within one year						(300	)		(375	)

Long-term debt					$	1,647		$	1,597

Long-term debt to financing trusts ^(c)
Subordinated debentures to PECO Trust III		7.38%		2028	$	81		$	81
Subordinated debentures to PECO Trust IV		5.75%		2033		103			103

Long-term debt to financing trusts					$	184		$	184

(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)	Amount owed to this financing trust is recorded as debt to financing trust within PECO’s Consolidated Balance Sheets.

BGE


			Maturity Date		December 31,
	Rates		Maturity Date		2012			2011
Long-term debt
Unsecured bonds		2.80% — 6.35%		2013-2036	$	1,850		$	1,710
Rate stabilization bonds		5.47% — 5.82%		2012-2017		332		$	395

Total long-term debt						2,182			2,105
Unamortized debt discount and premium, net						(4	)		(4	)
Long-term debt due within one year						(467	)		(173	)

Long-term debt					$	1,711		$	1,928

Long-term debt to financing trusts ^(a)
Subordinated debentures to BGE Capital Trust II		6.20%		2043	$	258		$	258

Long-term debt to financing trusts					$	258		$	258

(a)	Amount owed to this financing trust is recorded as debt to financing trust within BGE’s Consolidated Balance Sheets.

328

Combined Notes to Consolidated Financial Statements—(Continued)

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

Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2013 through 2017 and thereafter are as follows:


Year	Exelon			Generation		ComEd			PECO			BGE
2013	$	979		$	28	$	252		$	300		$	467
2014		1,483			616		617			250			70
2015		1,613			553		260			—			75
2016		1,041			76		665			—			379
2017		1,462			706		425			—			41
Thereafter		12,367	^(a)		5,292		3,574	^(b)		1,584	^(c)		1,408	^(d)

Total	$	18,945		$	7,271	$	5,793		$	2,134		$	2,440

(a)	Includes $648 million due to ComEd, PECO and BGE financing trusts.

(b)	Includes $206 million due to ComEd financing trust.

(c)	Includes $184 million due to PECO financing trusts.

(d)	Includes $258 million due to BGE financing trust.

Exelon Non-Recourse/Limited-Recourse Debt

The following are descriptions of certain indebtedness of Exelon’s project subsidiaries that are outstanding as of December 31, 2012. The indebtedness described below is non-recourse to Exelon, unless otherwise noted.

Antelope Valley Project Development Debt Agreement

The DOE Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project is expected to be completed at the end of 2013. The loan will mature on January 5, 2037. Interest rates on the loan will be fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity.

On April 5, 2012, Antelope Valley received the first DOE-guaranteed loan advance of $69 million. The loan advance terminated the put option that Generation had on the Antelope Valley project. Antelope Valley received additional advances subsequent to the initial advance, and as of December 31, 2012, has received $219 million in DOE-guaranteed funding. See Note 4—Merger and Acquisitions for additional information on Antelope Valley.

In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2012, Generation had $568 million in letters of credit outstanding related to the project The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made.

In connection with this agreement, Generation entered into a floating-for-fixed interest rate swap with a notional amount of $485 million to mitigate interest rate risk associated with the financing. As Generation received additional loan advances, they subsequently entered into a series of fixed-to-floating interest rate swaps to offset portions of the original interest rate hedge. See Note 10—Derivative Financial Instruments for additional information regarding interest rate swaps associated with Antelope Valley.

329

Combined Notes to Consolidated Financial Statements—(Continued)

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

Sacramento PV Energy

In July, 2011, a subsidiary of Generation entered into a $41 million non-recourse project financing supported by a 30MW solar facility in Sacramento, California. As of December 31, 2012, $39 million was outstanding. Borrowings under the facility bear interest at a variable rate, payable quarterly, and are secured by equity interests and assets of the subsidiary. As of December 31, 2012, the subsidiary had interest rate swaps with a notional value of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $39 million facility. See Note 10—Derivative Financial Instruments for additional information regarding interest rate swaps.

Constellation Solar Horizons Financing

In September 2012, a subsidiary of Generation entered into an 18-year $38 million non-recourse variable interest note to recover capital used to build a 16MW solar facility in Emmitsburg, Maryland. Borrowing will incur interest at a variable rate, payable quarterly, and are secured by the equity interests and assets of the subsidiary. The subsidiary also executed interest rate swaps for a notional amount of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $38 million facility amount. See Note 10—Derivative Financial Instruments for additional information regarding interest rate swaps.

Secured Solar Credit Lending Agreement. A subsidiary of Generation has a three-year senior secured credit facility that is designed to support the growth of solar operations. The amount committed under the facility is $150 million, which may be increased up to $200 million at the subsidiary’s request with additional commitments by the lenders. As of December 31, 2012, $113 million was outstanding under the facility with interest payable quarterly. The facility is secured by the equity interests in the subsidiary and the entities that own the solar projects as well as the assets of the subsidiary and the projects’ entities. The obligations of the subsidiary are guaranteed by Generation and the projects’ entities. The Generation guarantee will terminate upon the subsidiary obtaining a stand-alone investment grade credit rating or the satisfaction of a number of conditions, at which time the financing will become non-recourse to and Generation.

Other Solar Project Financings. Generation has the following amounts outstanding under solar project loan agreements:

•

$7 million fully amortizing by June 30, 2031 related to a solar project at the Denver International Airport, and

•

$11 million fully amortizing by December 31, 2031 related to a solar project in Holyoke, Massachusetts.

Upstream Gas Property Asset-Based Lending Agreement

Generation has a three year asset-based lending agreement associated with certain upstream gas properties that it owns. The borrowing base committed under the facility is $150 million and can increase to a total of $500 million if the assets support a higher borrowing base and Generation is able to obtain additional commitments from lenders. The facility was amended and extended through July 2016. Borrowings under this facility are secured by the upstream gas properties, and the lenders do not have recourse against Exelon or Generation in the event of a default. As of December 31, 2012, $72 million was outstanding under the facility with interest payable quarterly. The facility includes a provision that requires Generation entities that own the upstream gas properties subject to the agreement to maintain a current ratio of one-to-one. As of December 31, 2012, Generation was in compliant with this provision.

330

Combined Notes to Consolidated Financial Statements—(Continued)

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

12. Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

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


For the Year Ended December 31, 2012	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	37		$	104		$	(40	)	$	88		$	(97	)
Deferred		701			326			237			25			101
Investment tax credit amortization		(11	)		(6	)		(2	)		(2	)		(1	)
State
Current		(25	)		(12	)		6			4			—
Deferred		(75	)		88			38			12			4

Total	$	627		$	500		$	239		$	127		$	7


For the Year Ended December 31, 2011	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	1		$	431		$	(329	)	$	(71	)	$	(71	)
Deferred		1,200			435			544			223			130
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)		(1	)
State
Current		(3	)		74			(123	)		(37	)		—
Deferred		271			123			161			33			17

Total	$	1,457		$	1,056		$	250		$	146		$	75


For the Year Ended December 31, 2010	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	506		$	372		$	(203	)	$	464		$	(201	)
Deferred		972			635			496			(276	)		279
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)		(1	)
State
Current		171			65			(22	)		87			(2	)
Deferred		21			113			89			(121	)		22

Total	$	1,658		$	1,178		$	357		$	152		$	97

331

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, 2012	Exelon ^(a)			Generation ^(a)			ComEd			PECO			BGE ^(b)
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		(3.6	)		4.7			4.6			2.0			24.3
Qualified nuclear decommissioning trust fund income		5.4			9.1			—			—			—
Tax exempt income		(0.2	)		(0.4	)		—			—			—
Health care reform legislation		0.1			—			0.4			—			11.6
Amortization of investment tax credit, net deferred taxes		(1.1	)		(1.3	)		(0.4	)		(0.3	)		(8.6	)
Production tax credits and other credits		(2.2	)		(3.7	)		—			—			—
Plant basis differences		(2.4	)		—			(0.3	)		(11.5	)		(9.0	)
Merger expenses ^(c)		2.4			—			—			—			24.2
Fines and Penalties		2.6			4.4			—			—			—
Other		(1.1	)		(0.5	)		(0.6	)		(0.2	)		(13.9	)

Effective income tax rate		34.9	%		47.3	%		38.7	%		25.0	%		63.6	%


For the Year Ended December 31, 2011	Exelon			Generation			ComEd			PECO			BGE
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		4.4			4.5			3.6			(0.5	)		5.2
Qualified nuclear decommissioning trust fund income		0.5			0.7			—			—			—
Domestic production activities deduction		(0.3	)		(0.4	)		—			—			—
Tax exempt income		(0.2	)		(0.2	)		—			—			—
Health care reform legislation		(0.2	)		—			(1.0	)		—			(0.5	)
Amortization of investment tax credit		(0.3	)		(0.3	)		(0.4	)		(0.3	)		(0.5	)
Production tax credits		(0.9	)		(1.2	)		—			—			—
Plant basis differences		(1.0	)		—			(0.3	)		(6.9	)		(2.0	)
Other		(0.2	)		(0.7	)		0.6			—			(1.7	)

Effective income tax rate		36.8	%		37.4	%		37.5	%		27.3	%		35.5	%


For the Year Ended December 31, 2010	Exelon			Generation			ComEd			PECO			BGE
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.0			3.7			6.3			(4.7	)		5.5
Qualified nuclear decommissioning trust fund income		1.7			2.3			—			—			—
Domestic production activities deduction		(1.2	)		(1.5	)		—			—			—
Tax exempt income		(0.1	)		(0.2	)		—			—			—
Health care reform legislation		1.4			0.7			1.4			1.6			1.1
Amortization of investment tax credit		(0.3	)		(0.2	)		(0.4	)		(0.4	)		(0.4	)
Plant basis differences		—			—			(0.1	)		0.2			(1.0	)
Uncertain tax position remeasurement		—			(2.0	)		9.0			—			—
Other		(0.2	)		(0.4	)		0.2			0.2			(0.4	)

Effective income tax rate		39.3	%		37.4	%		51.4	%		31.9	%		39.8	%

332

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012.

(b)	BGE activity represents the activity for the twelve months ended December 31, 2012, 2011 and 2010.

(c)

Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger.

The tax effects of temporary differences, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2012 and 2011 are presented below:


For the Year Ended December 31, 2012	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(10,689	)	$	(3,545	)	$	(3,537	)	$	(2,437	)	$	(1,553	)
Accrual based contracts		(389	)		(389	)		—			—			—
Derivatives and other financial instruments		(392	)		(479	)		(4	)		—			—
Deferred pension and post-retirement obligation		1,225			(439	)		(598	)		(11	)		(12	)
Nuclear decommissioning activities		(604	)		(604	)		—			—			—
Deferred debt refinancing costs		(537	)		163			(25	)		(4	)		(4	)
Tax loss carryforward		421			226			32			14			105
Tax credit carryforward		226			226			—			—			—
Investment in CENG		(405	)		(419	)		—			—			—
Other, net		(25	)		9			(33	)		150			(186	)

Deferred income tax liabilities (net)	$	(11,169	)	$	(5,251	)	$	(4,165	)	$	(2,288	)	$	(1,650	)
Unamortized investment tax credits		(251	)		(216	)		(24	)		(3	)		(6	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,420	)	$	(5,467	)	$	(4,189	)	$	(2,291	)	$	(1,656	)


For the Year Ended December 31, 2011	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(7,803	)	$	(2,670	)	$	(3,264	)	$	(2,238	)	$	(1,220	)
Unrealized gains on derivative financial instruments		(468	)		(737	)		(4	)		—			—
Deferred pension and post-retirement obligation		665			(520	)		(623	)		(31	)		(93	)
Nuclear decommissioning activities		(452	)		(452	)		—			—			—
Deferred debt refinancing costs		(37	)		—			(31	)		(6	)		(4	)
Other, net		41			338			16			135			(226	)

Deferred income tax liabilities (net)	$	(8,054	)	$	(4,041	)	$	(3,906	)	$	(2,140	)	$	(1,543	)
Unamortized investment tax credits		(200	)		(169	)		(26	)		(5	)		(8	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(8,254	)	$	(4,210	)	$	(3,932	)	$	(2,145	)	$	(1,551	)

333

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, 2012.


	Exelon			Generation			ComEd		PECO			BGE
Federal
Federal net operating loss	$	635	^(a)	$	303		$	91	$	—		$	154
Federal capital loss carryforward		178	^(b)		178			—		—			—
Federal general business credits carryforward		226	^(c)		226			—		—			—

State
State net operating loss		3,365	^(d)		1,649	^(f)		—		209	^(h)		950	⁽ⁱ⁾
State capital loss carryforward		127	^(e)		119	^(g)		—		—			—
Deferred taxes on state tax attributes (net)		187			99			—		14			51
Valuation allowance on state tax attributes		36			35			—		—			1

(a)	Exelon’s federal net operating loss will expire beginning in 2033

(b)	Exelon’s federal capital loss carryforwards will expire beginning in 2018

(c)	Exelon’s federal general business credit carryforwards will expire beginning in 2033

(d)	Exelon’s state net operating losses will expire beginning in 2014

(e)	Exelon’s state capital loss carryforwards will expire beginning in 2018

(f)	Generation’s state net operating losses will expire beginning in 2014

(g)	Generation’s state capital loss carryforwards will expire beginning in 2018

(h)	PECO’s state net operating losses will expire beginning in 2032

(i)	BGE’s state net operating losses will expire beginning in 2026

Tabular reconciliation of unrecognized tax benefits

The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2012, 2011 and 2010:


	Exelon			Generation			ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2012	$	807		$	683		$	70		$	48		$	11
Merger Balance Transfer		195			183			—			—			—
Increases based on tax positions related to 2012		34			3			—			—			—
Change to positions that only affect timing		(88	)		(69	)		(3	)		(4	)		(11	)
Increases based on tax positions prior to 2012		91			91			—			—			—
Decreases based on tax positions prior to 2012		(6	)		(6	)		—			—			—
Decreases related to settlements with taxing authorities		(2	)		(2	)		—			—			—
Decreases from expiration of statute of limitations		(7	)		(7	)		—			—			—

Unrecognized tax benefits at December 31, 2012	$	1,024		$	876		$	67		$	44		$	—


	Exelon			Generation			ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2011	$	787		$	664		$	72		$	44		$	73
Increases based on tax positions related to 2011		5			1			—			4			—
Change to positions that only affect timing		21			24			(2	)		—			(62	)
Decreases based on tax positions prior to 2011		(3	)		(3	)		—			—			—
Decrease from expiration of statute of limitations		(3	)		(3	)		—			—			—

Unrecognized tax benefits at December 31, 2011	$	807		$	683		$	70		$	48		$	11

334

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Exelon			Generation			ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2010	$	1,498		$	633		$	471		$	372		$	112
Increases based on tax positions related to 2010		1			—			—			—			—
Decreases based on tax positions related to 2010		(2	)		(2	)		—			—			—
Change to positions that only affect timing		(262	)		55			(3	)		(328	)		(39	)
Increases based on tax positions prior to 2010		8			8			—			—			—
Decreases based on tax positions prior to 2010		(3	)		(3	)		—			—			—
Decreases related to settlements with taxing authorities		(452	)		(26	)		(396	)		—			—
Decrease from expiration of statute of limitations		(1	)		(1	)		—			—			—

Unrecognized tax benefits at December 31, 2010	$	787		$	664		$	72		$	44		$	73

Included in Exelon’s unrecognized tax benefits balance at December 31, 2012 and 2011 are approximately $730 million and $804 million, respectively, 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.

Unrecognized tax benefits that if recognized would affect the effective tax rate

Exelon and Generation have $294 million and $263 million, respectively, of unrecognized tax benefits at December 31, 2012 that, if recognized, would decrease the effective tax rate. Exelon and Generation had $3 million and $3 million, respectively, of unrecognized tax benefits at December 31, 2011 that, if recognized, would decrease the effective tax rate.

Total amounts of interest and penalties recognized

The following table represents the net interest receivable (payable), including interest related to uncertain tax positions reflected in the Registrants’ Consolidated Balance Sheets. Prior to the merger legacy Constellation recorded interest related to uncertain tax positions as a tax and not interest.


Net interest receivable (payable) as of	Exelon		Generation			ComEd		PECO		BGE
December 31, 2012	$	31	$	(20	)	$	107	$	2	$	—
December 31, 2011		74		33			23		28		(1	)

The following table sets forth the net interest expense, including interest related to uncertain tax positions, recognized in interest expense (income) in other income and deductions in the Registrants’ Consolidated Statements of Operations. The Registrants have not accrued any penalties with respect to uncertain tax positions. Prior to the merger legacy Constellation recorded interest related to uncertain tax positions as a tax and not interest.


Net interest expense (income) for the years ended	Exelon			Generation			ComEd			PECO			BGE
December 31, 2012	$	(1	)	$	11		$	(20	)	$	(1	)	$	9
December 31, 2011		(56	)		(40	)		(14	)		(1	)		(3	)
December 31, 2010		110			6			57			35			2

335

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 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. While the discovery phase of the litigation has been completed, no trial date has yet been assigned but could occur sometime in 2013.

During 2012, the parties agreed to take advantage of the court’s Alternative Dispute Resolution (ADR) program in an effort to resolve the dispute. The court’s ADR program provides a confidential and non-binding mediation process that tries to facilitate settlements. The parties participated in mediation discussions late in 2012 and these discussions are currently ongoing. Due to the possibility of quicker resolution through the ADR program, Generation believes that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next twelve months.

State Income Taxes

Generation has approximately $100 million of unrecognized tax benefits related to various state income tax return positions for which it is reasonably possible the unrecognized tax benefits could significantly change within 12 months due to the expiration of statutes of limitation or settlements with the state taxing authorities. Furthermore, Generation has approximately $55 million of unrecognized tax benefits related to state income tax refund claims that are currently being litigated. It is reasonably possible the unrecognized tax benefits of $55 million would decrease within 12 months.

See Other Tax Matters—Involuntary Conversion, Like Kind Exchange and Competitive Transition Charges 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		1999 - 2011
Constellation and subsidiaries consolidated Federal income tax returns		2005 - March 2012
Exelon and subsidiaries Illinois unitary income tax returns		2007 - 2011
Constellation combined New York corporate income tax returns		2008 - March 2012
Various separate company Pennsylvania corporate net income tax returns		2008 - March 2012
Various separate company Maryland corporate net income tax returns		2005 - March 2012

336

Combined Notes to Consolidated Financial Statements—(Continued)

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

Other Tax Matters

Involuntary Conversion, Like-Kind Exchange and Competitive Transition Charges

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 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 believed that it was economically compelled to dispose of ComEd’s fossil generating plants as a result of the Illinois Act and that the proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain could be deferred over the lives of the replacement property under the involuntary conversion provisions. The remaining 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. The IRS disagreed with both positions and asserted that the entire gain of approximately $2.8 billion was taxable in 1999.

Competitive Transition Charges (Exelon, ComEd, and PECO). Exelon contended 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 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, were excludible from taxable income as proceeds from an involuntary conversion. The tax basis of property acquired with the funds provided by the CTCs would be reduced such that the benefits of the position are temporary in nature. The IRS disallowed the refund claims for the 1999-2001 tax years.

Status of Involuntary Conversion and CTC Positions. In the second quarter of 2010, the IRS offered to settle the disagreement over the involuntary conversion and CTC positions. Exelon concluded, based on that offer, that it had sufficient new information that a remeasurement of the involuntary conversion and CTC positions was required in accordance with applicable accounting standards. As a result of the required remeasurement, Exelon recorded $65 million (after-tax) of interest expense, of which $36 million (after-tax) and $22 million (after-tax) were recorded at ComEd and PECO, respectively. ComEd also recorded a current tax expense of $70 million offset with a tax benefit recorded at Generation of $70 million. In the third quarter of 2010, Exelon and the IRS reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion on terms consistent with the settlement offer received in the second quarter. As a result of the preliminary agreement, Exelon and ComEd eliminated any liability for unrecognized tax benefits and established a current tax payable to the IRS. In November 2012, the IRS and Exelon finalized and executed definitive agreements to resolve Exelon’s involuntary conversion and CTC positions. Exelon paid $302 million in late 2010 in advance of the final settlement and the assessment.

Status of Like-Kind Exchange Position. Exelon has been unable to reach agreement with the IRS regarding the dispute over the like kind exchange position.

The IRS has 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

337

Combined Notes to Consolidated Financial Statements—(Continued)

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

facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $86 million for a substantial understatement of tax.

Exelon disagrees with the IRS and continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO. Exelon expects to initiate litigation in 2013 to contest the IRS’s disallowance of the like-kind exchange position. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, as of December 31, 2012, Exelon does not believe a settlement is possible. Because Exelon believed, as of December 31, 2012, that it was more-likely-than-not that Exelon would prevail in litigation, Exelon and ComEd had no liability for unrecognized tax benefits with respect to the like kind exchange position.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit reversed the U.S. Court of Federal Claims and reached a decision for the government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison’s deductions stemming from its participation in a LILO transaction that the IRS also has characterized as a tax shelter.

In accordance with applicable accounting standards, Exelon is required to assess whether it is more-likely-than-not that it will prevail in litigation. Exelon continues to believe that its transaction is not a SILO and that it has a strong case on the merits. However, in light of the Consolidated Edison decision and Exelon’s current determination that settlement is unlikely, Exelon has concluded that subsequent to December 31, 2012, it no longer meets the more-likely-than-not standard. As a result, Exelon expects to record in the first quarter of 2013 a non-cash charge to earnings of approximately $270 million, which represents the full amount of interest expense (after-tax) and incremental state tax expense in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $185 million will be recorded at ComEd and the balance at Exelon. Exelon and ComEd will continue to accrue interest on the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. Further, Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity. As a result of this hold harmless agreement, ComEd will record on its consolidated balance sheet non-cash equity contributions from Exelon in the amount of the net after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. The IRS also continues to assert an $86 million penalty for a substantial understatement of tax with respect to the like-kind exchange position. Exelon continues to believe that it is unlikely that the penalty assertion will ultimately be sustained and therefore no liability for the penalty has been recorded.

This determination for accounting purposes does not alter Exelon’s intent to aggressively litigate the issue through appeals, if necessary, which could take three to five years. Exelon currently expects to initiate the litigation in the United States Tax Court, whose decisions are not controlled by the Federal Circuit’s decision in Consolidated Edison.

As of March 31, 2013, in the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, the potential tax and after-tax interest, exclusive of penalties, that could become currently payable may be as much as $860 million, of which approximately $320 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless, and the balance at Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.

338

Combined Notes to Consolidated Financial Statements—(Continued)

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

Accounting for Generation Repairs (Exelon and Generation)

In 2009, Exelon received approval from the IRS to change its method of accounting for repair costs associated with Generation’s power plants. Although the IRS granted Exelon approval to change its method of accounting, the approval did not affirm the methodology used to calculate the deduction. In the second quarter of 2010, Exelon was informed that the IRS intended to issue broad industry guidance with respect to electric generation power plants. In anticipation of the issuance of this guidance, the IRS provided notice to Exelon in the third quarter of 2012 that it intended to apply the principles of Large Business & Industry Directive No. 4-0312-004, thereby deferring auditing Generation’s repair deductions until after issuance of the industry guidance and after Exelon has had an opportunity to change its accounting method to conform to that new guidance. As a result, in the third quarter of 2012, Exelon reduced its unrecognized tax benefits by approximately $107 million with an offsetting increase to its deferred tax liabilities and no net impact on results of operations.

The IRS is expected to issue industry guidance during 2013. Exelon and Generation will then determine the financial statement impacts of the generation repair costs accounting method change.

2011 Illinois State Tax Rate Legislation (Exelon, Generation and ComEd)

The Taxpayer Accountability and Budget Stabilization Act, (SB 2505), enacted into law in Illinois on January 13, 2011, increases the corporate tax rate in Illinois from 7.3% to 9.5% for tax years 2011 – 2014, provides for a reduction in the rate from 9.5% to 7.75% for tax years 2015 – 2024 and further reduces the rate from 7.75% to 7.3% for tax years 2025 and thereafter. Pursuant to the rate change, Exelon reevaluated its deferred state income taxes during the first quarter of 2011. Illinois’ corporate income tax rate changes resulted in a charge to state deferred taxes (net of Federal taxes) during the first quarter of 2011 of $7 million, $11 million and $4 million for Exelon, Generation and ComEd, respectively. Exelon’s and ComEd’s charge is net of a regulatory asset of $15 million.

In 2011, the income tax rate change increased Exelon’s Illinois income tax provision (net of Federal taxes) by approximately $7 million, of which $12 million and $5 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $10 million benefit for ComEd. The 2011 tax benefit at ComEd reflects the impact of a 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010 and the electric transmission and distribution property repairs deduction discussed below.

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. In 2010, the Registrants performed a review of the long-term state tax rates and noted no significant events that would materially impact state apportionment. As such, there was no update to the long-term state apportionment rates in 2010. In 2011 as a result of the 2011 Illinois State Tax Rate Legislation discussed above, Exelon and Generation re-evaluated their long-term state tax apportionment for Illinois and all other states where they have state income tax obligations. The effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax expense during the first quarter of 2011 of $22 million and $11 million (net of Federal taxes) for Exelon and Generation, respectively. The long-term state tax apportionment also was revised in the fourth quarter of 2011 pursuant to long-term state tax apportionment policy, resulting in recording an additional deferred state tax expense of $1 million and a deferred state tax benefit of $8 million (net of Federal taxes) for Exelon and Generation, respectively.

339

Combined Notes to Consolidated Financial Statements—(Continued)

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

As a result of the merger with Constellation, Exelon and Generation reevaluated their long-term state tax apportionment in the first quarter of 2012 for all states where they have state income tax obligations, which include Illinois, Maryland and Pennsylvania, as well as other states. The total effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax asset of $72 million (net of Federal taxes) for Exelon. Of this, a benefit in the amount of $116 million and $14 million (net of Federal taxes) was recorded for Exelon and Generation, respectively, for the three months ended March 31, 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44 million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the three months ended March 31, 2012. The long-term state tax apportionment also was updated in the fourth quarter of 2012, resulting in the recording of a deferred state tax benefit of $3 million (net of Federal taxes) for Exelon, and a deferred state tax expense of $7 million (net of Federal taxes) for Generation. There was no change to the long-term state tax apportionment for BGE, ComEd and PECO.

Accounting for Electric Transmission and Distribution Property Repairs (Exelon, Generation, ComEd, PECO and BGE)

On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. ComEd and PECO adopted the safe harbor in the Revenue Procedure for the 2011 and 2010 tax years, respectively. For the year ended December 31, 2011, the adoption of the safe harbor resulted in a $35 million reduction to income tax expense at PECO, while Generation incurred additional income tax expense in the amount of $28 million due to a decrease in its manufacturer’s deduction, which are reflected in the effective income tax rate reconciliation above in the plant basis differences and domestic production activities deduction lines, respectively. For Exelon, the adoption had a minimal effect on consolidated earnings. In addition, the adoption of the safe harbor resulted in a cash tax benefit at Exelon, ComEd and PECO in the amount of approximately $300 million, $250 million, $95 million respectively, partially offset by a cash tax detriment at Generation in the amount of $28 million related to a decreased domestic production activities deduction.

BGE adopted the safe harbor for the short period 2012 pre-merger tax year. For the year ended December 31, 2012, the adoption of the safe harbor resulted in a cash tax benefit at BGE in the amount of $27 million.

See Note 3—Regulatory Matters for discussion of the regulatory treatment prescribed in the 2010 electric distribution rate case settlement for PECO’s cash tax benefit resulting from the application of the method change to years prior to 2010.

Accounting for Gas Distribution Property Repairs (Exelon, PECO and BGE).

In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The change to the newly adopted method for the 2011 tax year and 2012 resulted in a tax benefit of $26 million at Exelon, of which $29 million in tax benefit is recorded at PECO, partially offset by an expense recorded at Generation to reflect a reduction in its domestic production activities deduction. BGE changed its method of accounting for gas distribution repairs for the 2008 tax year. The IRS is expected to issue industry guidance during 2013. Exelon, PECO and BGE will then determine the financial statement impacts of the gas distribution repair costs accounting method changes.

340

Combined Notes to Consolidated Financial Statements—(Continued)

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

Allocation of Tax Benefits (Exelon, Generation, ComEd, PECO and BGE)

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 2012, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $48 million and $9 million, respectively. During 2012, ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd’s 2012 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010. During 2011, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $30 million and $18 million, respectively. During 2011, ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd’s 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010 and the electric transmission and distribution property repairs deduction discussed above. During 2010, Generation, ComEd and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $60 million, $2 million and $43 million, respectively.

ComEd received a non-cash contribution to equity from Exelon in 2012 and 2011 of $11 million and $11 million, respectively, related to tax benefits associated with capital projects constructed by ComEd on behalf of Exelon and Generation.

13. Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. 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 that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

341

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2011 to December 31, 2012:


	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2011	$	3,276
Accretion expense		209
Net increase due to changes in, and timing of, estimated future cash flows		198
Costs incurred to decommission retired plants		(3	)

Nuclear decommissioning ARO at December 31, 2011 ^(a)		3,680
Accretion expense		231
Net increase due to changes in, and timing of, estimated future cash flows		833
Costs incurred to decommission retired plants		(3	)

Nuclear decommissioning ARO at December 31, 2012 ^(a)	$	4,741

(a)	Includes $10 million and $5 million as the current portion of the ARO at December 31, 2012 and 2011, respectively, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During 2012, Generation’s ARO increased by $1,061 million. The increase in the ARO is largely driven by the following four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have dramatically decreased given the current low interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities, Dresden and Clinton nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in estimated cash flows resulted in $10 million of expense, which is included in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

During 2011, Generation recorded a net increase in the ARO of $404 million primarily due to increases for accretion and an increase in the estimated costs to decommission the Oyster Creek and Zion nuclear units resulting from the completion of updated decommissioning cost studies received in 2011 and an increase in the expected long-term escalation rates for energy, partially offset by decreases in long-term escalation rates for labor and other costs as compared to prior study periods. The increase in the Zion nuclear unit ARO resulted in $28 million of expense, which is included in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, as the Zion nuclear unit is retired, and as such, is unable to record increases to the ARO through an ARC. Additionally, the Zion nuclear unit is not subject to a regulatory agreement that would provide for offset of the expense.

Zion Station Decommissioning

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those

342

Combined Notes to Consolidated Financial Statements—(Continued)

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

assets, ZionSolutions assumed decommissioning and other liabilities associated with Zion Station. Pursuant to the ASA, ZionSolutions can periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. On January 7, 2013, EnergySolutions announced that it had entered a definitive acquisition agreement to be acquired by another company. Generation has reviewed the acquisition as it relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activities under the ASA.

On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto. If the plaintiffs prevail on the merits of their claims, some or all of the NDT funds may no longer be available to ZionSolutions for decommissioning Zion Station, in which case, the contractual arrangement would require ZionSolutions to utilize a line of credit to complete the decommissioning. In addition, the appointment of a NDT fund trustee in this matter could impact Generation’s future decommissioning activities at other stations by setting a precedent for the appointment of trustees for NDT funds. On July 20, 2012, ZionSolutions and Bank of New York Mellon filed a motion to dismiss the amended complaint for failing to state a claim. The matter is currently under review by the court.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers. Generation has retained its obligation to transfer the SNF at Zion Station to the DOE for ultimate disposal and has a liability of approximately $79 million and $65 million at December 31, 2012 and 2011, respectively, which is included within the nuclear decommissioning ARO. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2012 and 2011:


	Exelon and Generation
	2012		2011
Carrying value of Zion Station pledged assets	$	614	$	734
Payable to Zion Solutions ^(a)		564		691
Current portion of payable to Zion Solutions ^(b)		132		128
Withdrawals by Zion Solutions to pay decommissioning costs		192		143

(a)	Excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.

(b)	Included in other current liabilities within Generation’s Consolidated Balance Sheets.

343

Combined Notes to Consolidated Financial Statements—(Continued)

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

ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed 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 is $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 the risk of default by EnergySolutions or ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions has also provided a performance guarantee and entered into other agreements that will provide rights and remedies for Generation and the NRC 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.

Nuclear Decommissioning Trust Fund Investments

NDT funds have been established for each generating station unit to satisfy Generation’s nuclear decommissioning obligations. NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT 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 NDT funds. Every five years, PECO files a rate adjustment with the PaPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. 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 NDT funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the NDT 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 NDT 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 NDTs after decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations

344

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 NDTs after decommissioning.

At December 31, 2012, and 2011, Exelon and Generation had NDT fund investments totaling $7,248 million and $6,507 million, respectively.

During 2012, the NDT fixed income portfolio completed its transition from solely core fixed income investments to a blend of Treasury Inflation Protected Securities (TIPS), investment-grade corporate credit and middle market lending. There was no change in the equity investment strategy. At December 31, 2012, approximately 47% of the funds were invested in equity securities and 53% were invested in fixed income securities. At December 31, 2011, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed income securities.

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 to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded on Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the types of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2012 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for Oyster Creek); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2012 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning activities are completed under three possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the assumption plants cease operating at the end of an extended license life (assuming 20-year license renewal extensions, except Oyster Creek with an assumed end-of-operations date of 2019); (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.3% to 6.2% (as compared to a historical 5-year annual average pre-tax return of approximately 3.6%).

345

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

On March 31, 2011, Generation, in its NRC-required biennial decommissioning funding status report, provided data from which the NRC concluded that the amount of decommissioning funding as of December 31, 2010 for Limerick Unit 1 was less than the amount required by the NRC’s regulations. Generation performed the calculations again in early 2012, which reflected that the amount of decommissioning funding as of December 31, 2011, for Limerick Unit 1 was less than the amount required by the NRC’s regulations. In February 2012, Generation obtained a parent guarantee in the amount of $115 million to cover the NRC minimum funding assurance requirements for Limerick Unit 1 and informed the NRC that it had addressed the minimum funding issues by, among other things, obtaining the parent guarantee. In a letter dated June 28, 2012, the NRC advised Generation of the NRC’s determination that the amount of decommissioning financial assurance provided in Generation’s plan was equal to or greater than the minimum required under the NRC regulations and that Generation had provided reasonable assurance that funds would be available for the Limerick Unit 1 decommissioning process.

On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Fund Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation’s status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. The NRC invited Generation to participate in a pre-decisional enforcement conference. At that conference, Generation will have an opportunity to explain its actions to the NRC. Generation will demonstrate that it did not deliberately or intentionally provide inaccurate or incomplete information in violation of the regulations and that it applied the regulatory provisions in a reasonable manner and in good faith. The letter from the NRC does not take issue with Generation’s current funding status. The NRC has publicly confirmed that Generation is currently sufficiently funded for decommissioning activities. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain.

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.

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 NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the NDT funds exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and

346

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income 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 NDT 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 and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s results of operations and financial position could be material. At December 31, 2012, the NDT 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, 2012 and is different, as described above, 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 and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income 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 Comprehensive Income, and the impact to Exelon’s and Generation’s results of operations and financial position could be material.

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 and Comprehensive Income, as there are no regulatory agreements associated with these units.

Refer to Note 3—Regulatory Matters and Note 22—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 to customers any decommissioning-related assets in excess of the related decommissioning obligations.

347

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table provides unrealized gains (losses) on NDT funds for 2012, 2011 and 2010:


	Exelon and Generation
	For the Years Ended December 31,
	2012		2011			2010
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units ^(a)^(b)(c)	$	386	$	(74	)	$	294
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units ^(c)		105		(4	)		104

(a)	Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)

Excludes $73 million and $48 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2012 and 2011. Net unrealized gains (losses) related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.

(c)	Net unrealized gains (losses) related to Generation’s NDT funds are included within other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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 and Comprehensive Income. 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’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

Non-Nuclear Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE)

Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. ComEd, PECO and BGE have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1—Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2011 to December 31, 2012:


	Exelon			Generation			ComEd			PECO			BGE
Non-nuclear AROs at January 1, 2011	$	223		$	86		$	105		$	32		$	1
Net decrease due to changes in, and timing of, estimated future cash flows ^(a)		(24	)		(3	)		(17	)		(4	)		—
Development projects		7			7			—			—			—
Accretion expense ^(b)		9			5			3			1			—
Payments		(6	)		(3	)		(2	)		(1	)		—

Non-nuclear AROs at December 31, 2011		209			92			89			28			1
Net increase due to changes in, and timing of, estimated future cash flows ^(a)		27			18			8			1			7
Development projects		47			47			—			—			—
Accretion expense ^(b)		13			8			4			1			—
Merger with Constellation ^(c)		58			50
Payments		(11	)		(8	)		(2	)		(1	)		—

Non-nuclear AROs at December 31, 2012	$	343		$	207		$	99		$	29		$	8

348

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)

During the year ended December 31, 2011, PECO recorded a reduction in operating and maintenance expense of $3 million. Generation and ComEd did not record any reductions in operating and maintenance expense for the year ended December 31, 2011. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2012.

(b)	For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

(c)	Exelon’s ARO includes $8 million of BGE costs incurred prior to the closing of Exelon’s merger with Constellation. Refer to Note 4—Merger and Acquisitions for additional information.

14. Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)

As of December 31, 2012, Exelon sponsored qualified defined benefit pension plans, non-qualified defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation’s benefit plans and its related assets. The table below shows the pension and postretirement benefit plans in which each operating company participated at December 31, 2012.

Operating Company

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

Qualified Pension Plans:

Exelon Corporation Retirement Program

Exelon Corporation Cash Balance Pension Plan

Exelon Corporation Pension Plan for Bargaining Unit Employees

Exelon New England Union Employees Pension Plan

Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek

Pension Plan of Constellation Energy Group, Inc.

BG New England Union Employees Pension Plan

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan

Exelon Corporation Supplemental Management Retirement Plan

Benefits Restoration Plan of Constellation Energy Group

Senior Executive Supplemental Pension Plan

Other Postretirement Benefit Plans:

PECO Energy Company Retiree Medical Plan

Exelon Corporation Health Care Program

Exelon Corporation Employees’ Life Insurance Plan

Constellation Energy Group, Inc. Retiree Medical Plan

Constellation Energy Group, Inc. Retiree Dental Plan

Constellation Energy Group, Inc. Life Insurance Plan and Family Life Insurance Plan

BG New England Post-Employment Medical Savings Account Plan

349

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon’s traditional and cash balance pension plans 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 these 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.

Benefit Obligations, Plan Assets and Funded Status

Exelon recognizes the overfunded or underfunded status of defined benefit pension and other postretirement benefit 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 measurement date for the plans is December 31. 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
	2012			2011			2012			2011
Change in benefit obligation:
Net benefit obligation at beginning of year	$	13,538		$	12,524		$	4,062		$	3,874
Service cost		280			212			156			142
Interest cost		698			649			205			207
Plan participants’ contributions		—			—			34			25
Actuarial loss		1,520			807			313			4
Plan amendments		—			—			(103	)		—
Acquisitions/divestitures		1,880						362
Curtailments		(10	)		—			(8	)		—
Settlements		(169	)		—			—			—
Contractual termination benefits		15			—			6			—
Gross benefits paid		(952	)		(654	)		(219	)		(201	)
Federal subsidy on benefits paid		—			—			12			11

Net benefit obligation at end of year	$	16,800		$	13,538		$	4,820		$	4,062

Change in plan assets:
Fair value of net plan assets at beginning of year	$	11,302		$	8,859		$	1,797		$	1,655
Actual return on plan assets		1,484			1,003			197			29
Employer contributions		149			2,094			325			277
Plan participants’ contributions		—			—			34			25
Benefits paid ^(a)		(952	)		(654	)		(218	)		(189	)
Acquisitions/divestitures		1,543			—			—			—
Settlements		(169	)		—			—			—

Fair value of net plan assets at end of year	$	13,357		$	11,302		$	2,135		$	1,797

(a)

Exelon’s other postretirement benefits paid for the years ended December 31, 2012 and 2011 are net of $1.3 million and $12 million, respectively, of reinsurance proceeds received from the Department of Health and Human Services as part of the Early Retiree Reinsurance Program pursuant to the Affordable Care Act of 2010.

350

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:


	Pension Benefits				Other Postretirement Benefits
	2012		2011		2012		2011
Other current liabilities	$	15	$	42	$	23	$	2
Pension obligations		3,428		2,194		—		—
Non-pension postretirement benefit obligations		—		—		2,662		2,263

Unfunded status (net benefit obligation less net plan assets)	$	3,443	$	2,236	$	2,685	$	2,265

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets. During the fourth quarter of 2012, Exelon completed an optional lump sum election program for select participants in certain of its qualified pension plans, which reduced the obligation and plan assets associated with those plans. This program decreased pension obligations and plan assets by approximately $425 million and $260 million, respectively, resulting in approximately $165 million overall funded status improvement.

The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets.


	PBO in excess of plan assets
	2012		2011
Projected benefit obligation	$	16,800	$	13,538
Fair value of net plan assets		13,357		11,302


	ABO in excess of plan assets
	2012		2011
Projected benefit obligation	$	16,796	$	13,538
Accumulated benefit obligation		15,657		12,616
Fair value of net plan assets		13,353		11,302

On a PBO basis, the plans were funded at 80% at December 31, 2012 compared to 83% at December 31, 2011. On an ABO basis, the plans were funded at 85% at December 31, 2012 compared to 90% at December 31, 2011. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.

351

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, 2012, 2011 and 2010 for all plans combined. The table reflects an increase in 2012, and a reduction in 2011 and 2010 of net periodic postretirement benefit costs of approximately $(17) million, $28 million and $38 million, respectively, related to a Federal subsidy provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Modernization Act), discussed further below.


	Pension Benefits									Other Postretirement Benefits
	2012			2011			2010			2012			2011			2010
Components of net periodic benefit cost:
Service cost	$	280		$	212		$	190		$	156		$	142		$	124
Interest cost		698			649			660			205			207			214
Expected return on assets		(988	)		(939	)		(799	)		(115	)		(111	)		(109	)
Amortization of:
Transition obligation		—			—			—			11			9			9
Prior service cost (credit)		15			14			14			(17	)		(38	)		(56	)
Actuarial loss		450			331			254			81			66			74
Curtailment charges		—			—			—			(7	)		—			—
Settlement charges		31			—			5			—			—			—
Contractual termination benefits ^(a)		14			—			—			6			—			1

Net periodic benefit cost	$	500		$	267		$	324		$	320		$	275		$	257

(a)	ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge.

Through Exelon’s postretirement benefit plans, the Registrants provide retirees with prescription drug coverage. The Medicare Modernization Act, enacted on December 8, 2003, introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans meets the requirements for the subsidy. See the Health Care Reform Legislation section below for further discussion regarding the income tax treatment of Federal subsidies of prescription drug benefits.

The effect of the subsidy on the components of net periodic postretirement benefit cost for the years ended December 31, 2012, 2011 and 2010 included in the consolidated financial statements was as follows:


	2012			2011		2010
Amortization of the actuarial experience loss	$	(17	)	$	3	$	9
Reduction in current period service cost		—			9		10
Reduction in interest cost on the APBO		—			16		19

Total effect of subsidy on net periodic postretirement benefit cost	$	(17	)	$	28	$	38

352

Combined Notes to Consolidated Financial Statements—(Continued)

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

Components of AOCI and Regulatory Assets

Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets for the years ended December 31, 2012, 2011 and 2010 for all plans combined.


	Pension Benefits									Other Postretirement Benefits
	2012			2011			2010			2012			2011			2010
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets:
Current year actuarial (gain) loss	$	1,693		$	744		$	737		$	304		$	74		$	—
Amortization of actuarial gain (loss)		(450	)		(331	)		(254	)		(81	)		(66	)		(74	)
Current year prior service (credit) cost		1			—			—			(109	)		—			—
Amortization of prior service (cost) credit		(15	)		(14	)		(14	)		17			38			56
Current year transition (asset) obligation		—									1
Amortization of transition asset (obligation)		—			—			—			(11	)		(9	)		(9	)
Curtailments		(10	)		—			—			(1	)		—			—
Settlements		(31	)		—			(5	)		—			—			—

Total recognized in AOCI and regulatory assets ^(a)	$	1,188		$	399		$	464		$	120		$	37		$	(27	)

(a)

Of the $1,188 million related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $399 million related to pension benefits, $181 million and $218 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $37 million related to other postretirement benefits, $13 million and $24 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $464 million related to pension benefits, $310 million and $154 million were recognized in AOCI and regulatory assets, respectively, during 2010. Of the $(27) million related to other postretirement benefits, $(9) million and $(18) million were recognized in AOCI and regulatory assets, respectively, during 2010.

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 at December 31, 2012 and 2011, respectively, for all plans combined:


	Pension Benefits				Other Postretirement Benefits
	2012		2011		2012			2011
Transition obligation	$	—	$	—	$	—		$	11
Prior service cost (credit)		76		90		(107	)		(16	)
Actuarial loss		7,931		6,729		1,185			963

Total ^(a)	$	8,007	$	6,819	$	1,078		$	958

(a)

Of the $8,007 million related to pension benefits, $4,594 million and $3,413 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $1,078 million related to other postretirement benefits, $514 million and $564 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $6,819 million related to pension benefits, $4,311 million and $2,508 million are included in AOCI and regulatory assets, respectively, at December 31, 2011. Of the $958 million related to other postretirement benefits, $475 million and $483 million are included in AOCI and regulatory assets, respectively, at December 31, 2011.

353

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 at December 31, 2012 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2013. These estimates are subject to the completion of an actuarial valuation of Exelon’s pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2013 and actual claims activity as of December 31, 2012. The valuation is expected to be completed in the first quarter of 2013 for legacy Exelon plans and in the second quarter of 2013 for legacy Constellation plans.


	Pension Benefits		Other Postretirement Benefits
Prior service cost (credit)	$	14	$	(19	)
Actuarial loss		568		84

Total ^(a)	$	582	$	65

(a)

Of the $582 million related to pension benefits at December 31, 2012, $315 million and $267 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. Of the $65 million related to other postretirement benefits at December 31, 2012, $29 million and $36 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively.

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirement plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, Exelon’s expected level of contributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and rate of compensation increases, employee age and length of service, among other factors.

Expected Rate of Return. In selecting the expected rate of return on plan assets, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.

354

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following assumptions were used to determine the benefit obligations for all of the plans at December 31, 2012, 2011 and 2010. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.


	Pension Benefits									Other Postretirement Benefits
	2012			2011			2010			2012			2011			2010
Discount rate		3.92	%		4.74	%		5.26	%		4.00	%		4.80	%		5.30	%
Rate of compensation increase			^(a)		3.75	%		3.75	%			^(a)		3.75	%		3.75	%
Mortality table		IRS required mortality table for 2013 funding valuation			IRS required mortality table for 2012 funding valuation			IRS required mortality table for 2011 funding valuation			IRS required mortality table for 2013 funding valuation			IRS required mortality table for 2012 funding valuation			IRS required mortality table for 2011 funding valuation
Health care cost trend on covered charges		N/A			N/A			N/A			6.50% decreasing to ultimate trend of 5.00% in 2017			6.50% decreasing to ultimate trend of 5.00% in 2017			7.00% decreasing to ultimate trend of 5.00% in 2015

(a)	3.25% for 2013-2017 and 3.75% thereafter.

The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2012, 2011 and 2010:


	Pension Benefits									Other Postretirement Benefits
	2012			2011			2010			2012			2011			2010
Discount rate		3.71	%^(a)		5.26	%		5.83	%		3.72	%^(a)		5.30	%		5.83	%
Expected return on plan assets		7.50	%^(b)		8.00	%^(b)		8.50	%^(b)		6.68	%^(b)		7.08	%^(b)		7.83	%^(b)
Rate of compensation increase		3.75	%		3.75	%		4.00	%		3.75	%		3.75	%		4.00	%
Mortality table		IRS required mortality table for 2012 funding valuation			IRS required mortality table for 2011 funding valuation			IRS required mortality table for 2010 funding valuation			IRS required mortality table for 2012 funding valuation			IRS required mortality table for 2011 funding valuation			IRS required mortality table for 2010 funding valuation
Health care cost trend on covered charges		N/A			N/A			N/A			6.50% decreasing to ultimate trend of 5.00% in 2017			7.00% decreasing to ultimate trend of 5.00% in 2015			7.50% decreasing to ultimate trend of 5.00% in 2015

355

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)

The initial discount rates used to establish Exelon’s pension and other postretirement benefits costs for 2012 were 4.74% and 4.80%, respectively. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates within the indicated ranges. 2012 costs reflect the impact of these remeasurements.

(b)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.

Assumed health care cost trend rates have a significant effect on the costs reported for the other postretirement benefit plans. A one percentage point change in assumed health care cost trend rates would have the following effects:


Effect of a one percentage point increase in assumed health care cost trend:
on 2012 total service and interest cost components	$	81
on postretirement benefit obligation at December 31, 2012		845
Effect of a one percentage point decrease in assumed health care cost trend:
on 2012 total service and interest cost components		(56	)
on postretirement benefit obligation at December 31, 2012		(569	)

Health Care Reform Legislation

In March 2010, the Health Care Reform Acts were signed into law, which contain a number of provisions that impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer’s postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to those offered by Medicare. Although this change did not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, Exelon recorded total after-tax charges of approximately $65 million to income tax expense to reverse deferred tax assets previously established. Generation, ComEd, PECO and BGE recorded charges of $24 million, $11 million, $9 million and $3 million, respectively. Additionally, as a result of this deductibility change for employers and other Health Care Reform provisions that impact the federal prescription drug subsidy options provided to employers, Exelon has made a change in the manner in which it will receive prescription drug subsidies beginning in 2013.

Additionally, the Health Care Reform Acts also include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Although the excise tax does not go into effect until 2018, accounting guidance requires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Certain key assumptions are required to estimate the impact of the excise tax on Exelon’s other postretirement benefit obligation, including projected inflation rates (based on the CPI) and whether pre- and post-65 retiree populations can be aggregated in determining the premium values of health care benefits. Exelon reflected its best estimate of the expected impact in its annual actuarial valuation.

356

Combined Notes to Consolidated Financial Statements—(Continued)

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

Contributions

The following table provides contributions made by Generation, ComEd, PECO, BGE and BSC to the pension and other postretirement benefit plans:


	Pension Benefits						Other Postretirement Benefits
	2012		2011		2010		2012^(a)		2011^(a)		2010^(a)
Generation	$	48	$	954	$	356	$	135	$	121	$	94
ComEd		25		873		260		119		108		60
PECO		13		110		73		33		28		35
BGE ^(b)		—		—		—		12		—		—
BSC		63		157		77		24		20		14

Exelon	$	149	$	2,094	$	766	$	323	$	277	$	203

(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, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012, $11 million, $5 million, $4 million, $1 million and $3 million, respectively, in 2011, and $10 million, $5 million, $3 million, $2 million and $2 million, respectively, in 2010.

(b)

BGE’s pension benefit contributions for 2012, 2011, and 2010 exclude $0 million, $54 million, and $197 million, respectively, of pension contributions made by BGE prior to the closing of Exelon’s merger with Constellation on March 12, 2012. BGE’s other postretirement benefit payments for 2012, 2011, and 2010 exclude $4 million, $13 million, and $17 million, respectively, of other postretirement benefit payments made by BGE prior to the closing of Exelon’s merger with Constellation on March 12, 2012. These pre-merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statements.

Exelon plans to contribute approximately $255 million to its qualified pension plans in 2013, of which Generation, ComEd, PECO and BGE will contribute $113 million, $116 million, $11 million and $0 million, respectively. Exelon plans to make non-qualified pension plan benefit payments of approximately $15 million in 2013, of which Generation, ComEd, PECO and BGE will pay $6 million, $1 million, $1 million and $2 million, respectively. Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Additionally, for Exelon’s largest qualified pension plan, the projected contributions reflect a funding strategy of contributing the greater of $250 million, which approximates service cost, or the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower minimum pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law will be applied in 2012 while others take effect in 2013. The estimated impacts of the law are reflected in the projected pension contributions.

357

Combined Notes to Consolidated Financial Statements—(Continued)

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

best assure continued rate recovery). Exelon expects to contribute approximately $292 million to the other postretirement benefit plans in 2013, of which Generation, ComEd, PECO and BGE expect to contribute $117 million, $114 million, $22 million and $18 million, respectively.

Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2012 were:


	Pension Benefits		Other Postretirement Benefits
	Pension Benefits		Other Postretirement Benefits
2013	$	943	$	197
2014		807		204
2015		891		212
2016		868		220
2017		902		231
2018 through 2022		5,161		1,330

Total estimated future benefit payments through 2022	$	9,572	$	2,394

Allocation to Exelon Subsidiaries

Generation, ComEd, PECO, and BGE 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, for the legacy Exelon plans 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 subsidiaries in the legacy Exelon plans 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. Pension and postretirement benefit contributions are allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. For legacy CEG plans, components of pension and other postretirement benefit costs and contributions are allocated to the subsidiaries based on employee participation (both active and retired). Pension assets are allocated such that each subsidiary has a funded status consistent with the overall plan.

The following approximate amounts were included in capital and operating and maintenance expense for the years ended December 31, 2012, 2011 and 2010, respectively, for Generation’s, ComEd’s, PECO’s, BSC’s and BGE’s allocated portion of the Exelon-sponsored pension and other postretirement benefit plans. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges:


For the Year Ended December 31,	Generation		ComEd		PECO		BSC ^(a)		BGE ^(b)(c)		Exelon
2012	$	341	$	282	$	50	$	99	$	60	$	820
2011		249		213		32		48		51		542
2010		268		215		46		52		48		581

(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

358

Combined Notes to Consolidated Financial Statements—(Continued)

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

(b)

The amounts included in capital and operating and maintenance expense for the years ended 2012, 2011, and 2010 include $12 million, $51 million, and $48 million, respectively, in costs incurred prior to the closing of Exelon’s merger with Constellation on March 12, 2012. These amounts are not included in Exelon’s capital and operating and maintenance expense for the years ended 2012, 2011, and 2010.

(c)	BGE’s pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset.

Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

Exelon has developed and implemented an investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. This investment strategy would tend to result in a lower expected rate of return on plan assets in future years. Trust assets for Exelon’s other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Exelon used an EROA of 7.50% and 6.45% to estimate its 2013 pension and other postretirement benefit costs, respectively.

Exelon’s pension and other postretirement benefit plan target asset allocations and December 31, 2012 and 2011 asset allocations were as follows:

Pension Plans


				Percentage of Plan Assets at December 31,
Asset Category	Target Allocation			2012			2011
Equity securities		34	%		35	%		32	%
Fixed income securities		40	%		40			47
Alternative investments ^(a)		26	%		25			21

Total					100	%		100	%

Other Postretirement Benefit Plans


				Percentage of Plan Assets at December 31,
Asset Category	Target Allocation			2012			2011
Equity securities		45	%		46	%		37	%
Fixed income securities		40	%		40			53
Alternative investments ^(a)		15	%		14			10

Total					100	%		100	%

(a)	Alternative investments include private equity, hedge funds and real estate.

359

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, 2012. 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, 2012, 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.

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 at December 31, 2012 and 2011:


At December 31, 2012 ^(a⁾	Level 1		Level 2			Level 3		Total
Pension plan assets
Cash equivalents	$	1	$	—		$	—	$	1
Equity securities:
Individually held		2,562		—			—		2,562
Commingled funds		—		1,111			—		1,111
Mutual funds ^(c)		323		—			—		323

Equity securities subtotal		2,885		1,111			—		3,996

Fixed income securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,037		—			—		1,037
Debt securities issued by states of the United States and by political subdivisions of the states		—		108			—		108
Foreign debt securities		—		252			—		252
Corporate debt securities		—		3,330			—		3,330
Federal agency mortgage-backed securities		—		117			—		117
Non-Federal agency mortgage-backed securities		—		28			—		28
Commingled funds		—		274			—		274
Mutual funds ^(c)		4		291			—		295
Derivative instruments ^(b):
Assets		—		9			—		9
Liabilities		—		(21	)		—		(21	)

Fixed income securities subtotal		1,041		4,388			—		5,429

Private equity		—		—			754		754
Hedge funds		—		1,080			1,235		2,315
Real estate:
Individually held		280		—			—		280
Commingled funds		—		75			—		75
Real estate funds		—		—			426		426

Real estate subtotal		280		75			426		781

Pension plan assets subtotal		4,207		6,654			2,415		13,276

360

Combined Notes to Consolidated Financial Statements—(Continued)

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


At December 31, 2012 ^(a⁾	Level 1		Level 2		Level 3		Total
Other postretirement benefit plan assets
Cash equivalents		44		—		—		44
Equity securities:
Individually held		198		—		—		198
Commingled funds		—		530		—		530
Mutual funds ^(c)		230		—		—		230

Equity securities subtotal		428		530		—		958

Fixed income securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		18		—		—		18
Debt securities issued by states of the United States and by political subdivisions of the states		—		125		—		125
Foreign debt securities		—		3		—		3
Corporate debt securities		—		50		—		50
Federal agency mortgage-backed securities		—		52		—		52
Non-Federal agency mortgage-backed securities		—		6		—		6
Commingled funds		—		271		—		271
Mutual funds ^(c)		295		2		—		297

Fixed income securities subtotal		313		509		—		822

Private equity		—		—		1		1
Hedge funds		—		188		12		200
Real estate:
Individually held		7		—		—		7
Commingled funds		—		2		—		2
Real estate funds		—		6		95		101

Real estate subtotal		7		8		95		110

Other postretirement benefit plan assets subtotal		792		1,235		108		2,135

Total pension and other postretirement benefit plan assets ^(d)(e)	$	4,999	$	7,889	$	2,523	$	15,411

361

Combined Notes to Consolidated Financial Statements—(Continued)

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


At December 31, 2011 (a)	Level 1		Level 2		Level 3		Total
Pension plan assets
Cash equivalents	$	8	$	—	$	—	$	8
Equity securities:
Individually held		1,985		—		—		1,985
Commingled funds		—		858		—		858
Mutual funds		—		389		—		389

Equity securities subtotal		1,985		1,247		—		3,232

Fixed income securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,616		48		—		1,664
Debt securities issued by states of the United States and by political subdivisions of the states		—		88		—		88
Foreign debt securities		—		224		—		224
Corporate debt securities		—		2,561		—		2,561
Federal agency mortgage-backed securities		—		156		—		156
Non-Federal agency mortgage-backed securities		—		28		—		28
Commingled funds		—		202		—		202
Mutual funds		—		277		—		277

Fixed income securities subtotal		1,616		3,584		—		5,200

Private equity		—		—		672		672
Hedge funds ^(f)		—		—		1,525		1,525
Real estate:
Individually held		207		—		—		207
Commingled funds		—		125		—		125
Real estate funds		—		—		229		229

Real estate subtotal		207		125		229		561

Pension plan assets subtotal		3,816		4,956		2,426		11,198

Other postretirement benefit plan assets
Cash equivalents		73		—		—		73
Equity securities:
Individually held		110		—		—		110
Commingled funds		—		415		—		415
Mutual funds		—		171		—		171

Equity securities subtotal		110		586		—		696

Fixed income securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		26		3		—		29
Debt securities issued by states of the United States and by political subdivisions of the states		—		93		—		93
Foreign debt securities		—		4		—		4
Corporate debt securities		—		41		—		41
Federal agency mortgage-backed securities		—		34		—		34
Non-Federal agency mortgage-backed securities		—		7		—		7
Commingled funds		—		385		—		385
Mutual funds		—		256		—		256

Fixed income securities subtotal		26		823		—		849

Private equity		—		—		1		1
Hedge funds ^(f)		—		—		157		157
Real estate
Individually held		4		—		—		4
Commingled funds		—		1		—		1
Real Estate funds		—		—		7		7

Real estate subtotal		4		1		7		12

Other postretirement benefit plan assets subtotal		213		1,410		165		1,788

Total pension and other postretirement benefit plan assets ^(d)	$	4,029	$	6,366	$	2,591	$	12,986

362

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	See Note 9—Fair Value of Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)

Derivative instruments have a total notional amount of $2,498 million and $910 million at December 31, 2012 and 2011, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

(c)

In 2012, Exelon reassessed its policy over the criteria that mutual fund investments must meet in order to be categorized within Level 1 of the fair value hierarchy. Therefore, certain mutual fund investments that were categorized within Level 2 in prior periods have been re-categorized as Level 1 investments as of December 31, 2012. The re-categorization of these mutual fund investments resulted in a transfer out of Level 2 of $852 million.

(d)

Excludes net assets of $77 million and $43 million at December 31, 2012 and 2011 respectively; which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.

(e)	Includes fixed income commingled fund assets of $66 million as of December 31, 2012. The fair value of these fixed income commingled fund assets of $69 million, as of December 31, 2011, are excluded from the tables above.

(f)

In 2012, Exelon refined its policy over the criteria that hedge fund investments must meet in order to be categorized within Level 2 and Level 3 of the fair value hierarchy. Therefore, certain hedge fund investments that were categorized within Level 3 in prior periods have been re-categorized as Level 2 investments as of December 31, 2012. The re-categorization of these hedge fund investments is reflected as transfers out of Level 3 of $1.1 billion.

The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 2012 and 2011:


	Hedge funds			Private equity			Real estate			Total
Pension Assets
Balance as of January 1, 2012	$	1,525		$	672		$	229		$	2,426
Actual return on plan assets:
Relating to assets still held at the reporting date		138			55			24			217
Purchases, sales and settlements:
Purchases		447			108			134			689
Sales		(6	)		—			—			(6	)
Settlements		(4	)		(128	)		(28	)		(160	)
Transfers into (out of) Level 3 ^(a)(b)(c)		(865	)		47			67			(751	)

Balance as of December 31, 2012	$	1,235		$	754		$	426		$	2,415

Other Postretirement Benefits
Balance as of January 1, 2012	$	157		$	1		$	7		$	165
Actual return on plan assets:
Relating to assets still held at the reporting date		11			—			3			14
Purchases, sales and settlements:
Purchases		32			—			91			123
Sales		—			—			—			—
Settlements		—			—			(1	)		(1	)
Transfers into (out of) Level 3 ^(a)(b)(c)		(188	)		—			(5	)		(193	)

Balance as of December 31, 2012	$	12		$	1		$	95		$	108

363

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Hedge funds			Private equity			Real estate			Total
Pension Assets
Balance as of January 1, 2011	$	329		$	536		$	179		$	1,044
Actual return on plan assets ^(d):
Relating to assets still held at the reporting date		(26	)		84			46			104
Purchases, sales and settlements ^(d):
Purchases		1,222			121			13			1,356
Sales		—			—			—			—
Settlements		—			(69	)		(9	)		(78	)
Transfers into (out of) Level 3		—			—			—			—

Balance as of December 31, 2011	$	1,525		$	672		$	229		$	2,426

Other Postretirement Benefits
Balance as of January 1, 2011	$	5		$	—		$	8		$	13
Actual return on plan assets:
Relating to assets still held at the reporting date		(3	)		—			(1	)		(4	)
Purchases, sales and settlements:
Purchases		155			1			—			156
Sales		—			—			—			—
Settlements		—			—			—			—
Transfers into (out of) Level 3		—			—			—			—

Balance as of December 31, 2011	$	157		$	1		$	7		$	165

(a)	In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation’s pension plan assets resulting in transfers into Level 3 of $141 million.

(b)

(c)	In 2012, the liquidity terms of a certain real estate investment changed to allow redemption within a reasonable period of time from the redemption date which led to a transfer out of Level 3 to Level 2 of $5 million.

(d)	Certain prior year amounts have been reclassified for comparative purposes.

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 and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

Equity securities. With respect to individually held equity securities, including investments in U.S. and international 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. Equity securities held individually are primarily traded on exchanges that contain only actively traded securities, due to the volume trading requirements imposed by these exchanges. Equity securities are valued based on quoted prices in active markets and are categorized as Level 1.

Equity commingled funds and mutual funds are maintained by investment companies that hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets

364

Combined Notes to Consolidated Financial Statements—(Continued)

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

and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, mutual funds and derivative instruments, the trustees obtain multiple prices 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 as 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.

Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized as Level 2.

Fixed income commingled funds and mutual funds, including short-term investment 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 some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2.

Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows and market based comparable data. Since these valuation inputs are not highly observable, private equity investments have been categorized as Level 3.

Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or ownership interest of the investments. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate. For Exelon’s investments that have terms that allow redemption within a reasonable period of time from the measurement date, the hedge fund investments are categorized as Level 2. For investments that have restrictions that may limit

365

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon’s ability to redeem the investments at the measurement date or within a reasonable period of time, the hedge fund investments are categorized as Level 3.

Real estate. Real estate investment trusts valued daily based on quoted prices in active markets are categorized as Level 1. Real estate 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. Since these funds are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Other real estate 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, these real estate funds have been categorized as Level 3.

Defined Contribution Savings Plan (Exelon, Generation, ComEd, PECO and BGE)

Exelon, Generation, ComEd, PECO and BGE participate in a 401(k) defined contribution savings plan sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon, Generation, ComEd, PECO and BGE match a percentage of the employee contribution up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2012, 2011 and 2010:


For the Year Ended December 31,	Exelon		Generation		ComEd		PECO		BGE
2012	$	67	$	30	$	19	$	7	$	7
2011		78		40		22		9		7
2010		81		42		22		9		6

15. Plant Retirements (Exelon and Generation)

Schuylkill Station and Riverside Station

On October 31, 2012, Generation notified PJM of its intention to permanently retire Schuylkill Generating Station Unit 1 by February 1, 2013, and Riverside Generating Station Unit 6 by June 1, 2014. Schuylkill Unit 1 is a 166 MW peaking oil unit located in Philadelphia, Pennsylvania, which was placed in service in 1958. Riverside Unit 6 is a 115 MW peaking gas/kerosene unit located in Baltimore, Maryland, which was placed in service in 1970. The units are being retired because they are no longer economic to operate due to their age, relatively high capital and operating costs and declining revenue expectations. On November 30, 2012, PJM notified Generation that it did not identify any transmission system reliability issues associated with the proposed Schuylkill Unit 1 retirement date and as a result, Schuylkill Unit 1 was retired on January 1, 2013. On January 7, 2013, PJM notified Generation that it did not identify any transmission system reliability issues associated with the proposed Riverside Unit 6 retirement date. Exelon will determine the final retirement date for Riverside Unit 6 during the second quarter of 2013. The early retirements will not have a material impact on Generation or Exelon’s results of operations, cash flows or financial position.

Oyster Creek

On December 8, 2010, in connection with the executed Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019.

366

Combined Notes to Consolidated Financial Statements—(Continued)

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

Eddystone Station and Cromby Station

In 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011, in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that will permit Generation’s retirement of two of the units on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; Cromby Unit 2 retired on December 31, 2011 and Eddystone Unit 2 retired on May 31, 2012. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defines compensation to be paid to Generation for continuing to operate these units. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 is approximately $6 million. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In addition, Generation is reimbursed for variable costs, including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 operated under the reliability-must-run agreement from June 1, 2011 until their respective retirement dates.

Since the announced retirements in December 2009, Generation recorded pre-tax expense of $44 million, which included $18 million of expense for the write down of inventory, $13 million of expense for estimated salary continuance and health and welfare severance benefits and $13 million of shut down costs recorded within operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

During the year ended December 31, 2012, Generation recorded $1 million of expense for the write down of inventory and $11 million of shut down costs. During the year ended December 31, 2011, Generation recorded pre-tax expense of $4 million for estimated salary continuance and health and welfare severance benefits and $2 million of shut down costs.

The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements from January 1, 2011 through December 31, 2012:


Severance Benefits Obligation	Exelon and Generation
Balance at January 1, 2011	$	7
Severance charges recorded		4
Cash payments		(4	)

Balance at December 31, 2011		7
Cash payments		(4	)

Balance at December 31, 2012	$	3

16. Preferred and Preference Securities (Exelon, ComEd, PECO and BGE)

At December 31, 2012 and 2011, 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, 2012 and 2011, 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.

367

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2012 and 2011, 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.


			December 31,
	Redemption Price ^(a)		2012		2011		2012		2011
	Redemption Price ^(a)		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.

At December 31, 2012 and 2011, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized and the outstanding amounts set forth below. Shares of BGE preference stock have no voting power except for the following:

•

The preference stock has one vote per share on any charter amendment which would create or authorize any shares of stock ranking prior to or on a parity with the preference stock as to either dividends or distribution of assets, or which would substantially adversely affect the contract rights, as expressly set forth in BGE’s charter, of the preference stock, each of which requires the affirmative vote of two-thirds of all the shares of preference stock outstanding; and

•

Whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.


			December 31,
	Redemption Price ^(a)		2012		2011		2012		2011
	Redemption Price ^(a)		Shares Outstanding				Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.36		400,000		400,000	$	40	$	40
6.97%, 1993 Series		100.35		500,000		500,000		50		50
6.70%, 1993 Series		100.67		400,000		400,000		40		40
6.99%, 1995 Series		101.05		600,000		600,000		60		60

Total preference stock				1,900,000		1,900,000	$	190	$	190

(a)	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.

368

Combined Notes to Consolidated Financial Statements—(Continued)

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

17. Common Stock (Exelon, Generation, ComEd, PECO and BGE)

At December 31, 2012 and 2011, Exelon’s common stock without par value consisted of 2,000,000,000 shares authorized and 854,781,389 shares and 663,368,958, shares outstanding, respectively. At December 31, 2012 and 2011, ComEd’s common stock with a $ 12.50 par value consisted of 250,000,000 shares authorized and 127,016,761 shares and 127,016,529 shares outstanding, respectively. At December 31, 2012 and 2011, PECO’s common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding. At December 31, 2012 and 2011, BGE’s common stock without par value consisted of 175,000,000 shares authorized and 1,000 shares outstanding.

ComEd had 74,182 and 75,096 warrants outstanding to purchase ComEd common stock at December 31, 2012 and 2011, 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, 2012 and 2011, 24,727 and 25,032 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 allowed Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program was 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 had no specified limit on the number of shares that could be repurchased and no specified termination date. Any shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management.

In the third quarter of 2008, Exelon’s Board of Directors approved a share repurchase program for $1.5 billion of its common stock. Subsequently, Exelon’s 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 dating back to 2004, 34.7 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2012. During 2012, 2011 and 2010, 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, 2012, there were approximately 20 million shares authorized for issuance under the LTIP. For the years ended December 31, 2012, 2011 and 2010, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

369

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, PECO and BGE 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.

In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation’s 1995 Long-Term Incentive Plan, 2002 Senior Management Long-Term Incentive Plan, Amended and Restated 2007 Long-Term Incentive Plan, Amended and Restated Management Long-Term Incentive Plan and Executive Long-Term Incentive Plan (collectively and as amended, if applicable, the “Constellation Plans”). Stock-based awards granted under the Constellation Plans and held by Constellation employees were generally converted into outstanding Exelon stock-based compensation awards with the estimated fair value determined to be $71 million using the Black-Scholes model. Refer to Note 4 - Merger and Acquisitions for further information regarding the merger transaction. Specifically, as of the merger closing: (1) Exelon converted 12,037,093 outstanding shares that were subject to Constellation stock options into 11,194,151 Exelon stock options valued at $65 million; and (2) Exelon converted 165,219 Constellation no-sale restricted stock units into 153,654 Exelon no-sale restricted stock units valued at $6 million.

Exelon generally grants most of its stock options in the first quarter of each year. In connection with the merger with Constellation, the Compensation Committee of Exelon’s Board of Directors elected to delay the annual equity award grant from January 2012 to the effective date of the merger on March 12, 2012, in order to ensure that a majority of eligible employees receive grants on the same date and at the same market price.

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010:


	Year Ended December 31,
Components of Stock-Based Compensation Expense	2012			2011			2010
Performance share awards	$	46		$	26		$	6
Stock options		15			8			10
Restricted stock units		50			31			21
Other stock-based awards		4			4			4

Total stock-based compensation expense included in operating and maintenance expense		115			69			41
Income tax benefit		(44	)		(27	)		(16	)

Total after-tax stock-based compensation expense	$	71		$	42		$	25

370

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2012, 2011 and 2010:


	Year Ended December 31,
Subsidiaries	2012^(a)		2011		2010
Generation	$	42	$	31	$	21
ComEd		11		5		3
PECO		5		5		3
BGE		5		6		4
BSC ^(b)		52		28		14

Total	$	115	$	69	$	41

(a)	For BGE, reflects BGE’s stock-based compensation expense for the year ended December 31, 2012. For Exelon and Generation, includes the stock-based compensation expense of Constellation and BGE from the date of the merger, March 12, 2012, through December 31, 2012.

(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.

There were no significant stock-based compensation costs capitalized during the years ended December 31, 2012, 2011 and 2010.

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 for the years ended December 31, 2012, 2011 and 2010:


	Year Ended December 31,
	2012		2011		2010
Realized tax benefit when exercised/distributed:
Stock options	$	3	$	2	$	5
Restricted stock units		11		8		9
Performance share awards		7		7		13
Stock deferral plan		—		1		1
Excess tax benefits included in other financing activities of Exelon’s
Consolidated Statements of Cash Flows:
Stock options	$	2	$	1	$	3

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.

371

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 2012, 2011 and 2010 were not significant.

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, 2012, 2011 and 2010:


	Year Ended December 31,
	2012			2011			2010
Dividend yield		5.28	%		4.84	%		4.56	%
Expected volatility		23.20	%		24.40	%		27.10	%
Risk-free interest rate		1.30	%		2.65	%		2.96	%
Expected life (years)		6.25			6.25			6.25
Weighted average grant date fair value (per share)	$	4.18		$	6.22		$	8.08

The assumptions above relate to Exelon stock options granted during the period and therefore do not include stock options that were converted in connection with the merger with Constellation during the year ended December 31, 2012.

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.

372

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents information with respect to stock option activity for the year ended December 31, 2012:


	Shares			Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)		Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2011		11,553,761		$	48.49
Options granted		2,372,000			39.66
Converted Constellation options		11,194,151			41.35
Options exercised		(1,776,041	)		26.41
Options forfeited		(980,986	)		42.90
Options expired		(459,104	)		49.45

Balance of shares outstanding at December 31, 2012		21,903,781		$	45.91		5.58	$	13

Exercisable at December 31, 2012 ^(a)		19,943,116		$	46.40		5.25	$	13

(a)	Includes stock options issued to retirement eligible employees.

The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2012, 2011 and 2010:


	Year Ended December 31,
	2012		2011		2010
Intrinsic value ^(a)	$	19	$	5	$	13
Cash received for exercise price		47		13		24

(a)	The difference between the market value on the date of exercise and the option exercise price.

The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2012:


	Shares			Weighted Average Exercise Price (per share)
Nonvested at December 31, 2011 ^(a)		877,050		$	48.66
Granted ^(b)		2,372,000			39.66
Converted Constellation options		11,194,151			41.35
Vested ^(b)(c)		(12,023,432	)		41.37
Forfeited		(459,104	)		49.45

Nonvested at December 31, 2012 ^(a)		1,960,665		$	40.56

(a)	Excludes 2,647,536 and 1,348,000 of stock options issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b)	Includes 8,684,709 of converted Constellation options that were vested prior to the Merger on March 12, 2012.

(c)	Includes 1,699,000 of stock options issued to retirement-eligible employees in 2012 that vested immediately upon the employee reaching retirement eligibility.

At December 31, 2012, $6 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 2.4 years.

373

Combined Notes to Consolidated Financial Statements—(Continued)

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

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

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 as necessary.

The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2012:


	Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2011 ^(a)		1,074,484		$	48.08
Granted		1,332,214			39.94
Converted Constellation restricted stock		825,735			38.91
Vested		(479,805	)		46.36
Forfeited		(76,484	)		42.21
Undistributed vested awards ^(b)		(646,983	)		40.75

Nonvested at December 31, 2012 ^(a)		2,029,161		$	42.12

(a)	Excludes 686,121 and 448,827 of restricted stock units issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2012.

The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2012, 2011 and 2010 was $39.94, $43.33 and $44.23, respectively. At December 31, 2012 and 2011, Exelon had obligations related to outstanding restricted stock units not yet settled of $58 million and $46 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2012, 2011 and 2010, Exelon settled restricted stock units with fair value totaling $25 million, $19 million and $22 million, respectively. At December 31, 2012, $43 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.9 years.

Performance Share Awards

Performance share awards are granted under the LTIP with the 2012 performance share awards being settled in 50% common stock and 50% cash over the three-year vesting term. The 2011 performance share awards are being settled entirely in common stock over the three-year vesting term. The performance shares granted prior to 2011 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period.

374

Combined Notes to Consolidated Financial Statements—(Continued)

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

These awards are recorded at fair value at the date of grant with the estimated grant date fair value based on the expected payout of the award, which may range from 75% to 125% of the payout target. The common stock portion is considered an equity award with the 75% payout floor being valued based on Exelon’s stock price on the grant date. The cash portion of the award is considered a liability award with the 75% payout floor being remeasured each reporting period based on Exelon’s current stock price. The expected payout in excess of the 75% floor for the equity and liability portions are remeasured each reporting period based on Exelon’s current stock price and changes in the expected payout of the award; therefore these portions of the award are subject to volatility until the payout is established.

In 2010, the number of performance shares granted was 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 these 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.

The 2010 performance share awards that were settled in stock were recorded as common stock within the Consolidated Balance Sheets and 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 2010 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. The 2010 performance share awards that were settled in cash were recorded as liabilities within the Consolidated Balance Sheets. The grant date fair value of liability classified performance share awards granted during the year ended 2010 was based on historical data for the previous two plan years and actual results for the current plan year. The liabilities were remeasured each reporting period throughout the requisite service period and as a result, the compensation costs for cash-settled awards were 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, 2012:


	Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2011 ^(a)		346,848		$	45.37
Granted		1,429,189			39.72
Vested		(167,048	)		47.46
Forfeited		(116,388	)		39.78
Undistributed vested awards ^(b)		(179,867	)		40.72

Nonvested at December 31, 2012 ^(a)		1,312,734		$	40.08

375

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	Excludes 204,643 and 455,418 of performance share awards issued to retirement-eligible employees as of December 31, 2012 and December 31, 2011, respectively, as they are fully vested.

(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2012.

The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2012, 2011 and 2010 was $39.71, $43.52 and $60.82 respectively. During the years ended December 31, 2012, 2011 and 2010, Exelon settled performance shares with a fair value totaling $23 million, $22 million and $32 million, respectively, of which $3 million, $10 million and $20 million was paid in cash, respectively. As of December 31, 2012, $9 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 2.2 years.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:


	December 31,
	2012		2011
Current liabilities ^(a)	$	7	$	3
Deferred credits and other liabilities ^(b)		11		—
Common stock		35		30

Total	$	53	$	33

(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.

18. 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:


	Year Ended December 31,
	2012		2011		2010
Net income on common stock	$	1,160	$	2,495	$	2,563

Weighted average common shares outstanding—basic		816		663		661
Assumed exercise and/or distributions of stock-based awards		3		2		2

Weighted average common shares outstanding—diluted		819		665		663

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 14 million in 2012, 9 million in 2011 and 8 million in 2010.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of December 31, 2012. In 2008, Exelon management decided to defer indefinitely any share repurchases.

376

Combined Notes to Consolidated Financial Statements—(Continued)

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

19. Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)

Nuclear Insurance

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2012, 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. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective October 29, 2008. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of January 1, 2013, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in an additional $12.2 billion in funds available for public liability claims. Participation in this secondary 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 financial protection. 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 $2.2 billion. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $12.6 billion limit for a single incident.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. No distributions were declared in 2011 or 2012. Premiums paid to NEIL by its members are subject to assessment (the retrospective premium obligation) for adverse loss experience. NEIL has never exercised this assessment since its formation in 1973, and while Generation cannot predict the level of future assessments, or if they will be imposed at all, as of December 31, 2012, the current maximum aggregate annual retrospective premium obligation for Generation is approximately $278 million.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. As of December 31, 2012, Generation’s current limit for this coverage is $2.1 billion. 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. In the event of an insured loss, Generation is

377

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 $220 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 $58 million per year (the retrospective premium obligation). 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.

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. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.

Spent Nuclear Fuel Obligation

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 ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly.

The 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. In early 2010, Secretary of Energy Steven Chu appointed the Blue Ribbon Commission (BRC) on America’s Nuclear Future to evaluate and recommend a new plan for managing the back end of the nuclear fuel cycle, including used fuel storage, disposal and fees. The Commission released its final report to the U.S. Energy Secretary on January 26, 2012, detailing

378

Combined Notes to Consolidated Financial Statements—(Continued)

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

comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s spent nuclear fuel and high-level radioactive waste. The strategy recommended by the Commission encompasses 8 key elements; 1) A new consent-based approach to siting storage and disposal facilities; 2) A new organization to implement the waste management program; 3) Access to utility waste disposal fees for their intended purpose; 4) Prompt efforts to develop a new geological disposal facility; 5) Prompt efforts to develop one or more consolidated storage facilities; 6) Early preparation for the eventual large-scale transport of spent nuclear fuel and high-level waste to consolidated storage and disposal facilities; 7) Support for advances in nuclear energy technology and for workforce development; and 8) Active U.S. leadership in international efforts to address safety, non-proliferation and security concerns.

In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that is planned to be operational in 2025.

Generation uses the 2025 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nuclear decommissioning asset retirement obligations. The extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Clinton, 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 2030 and determined that Generation’s aggregate nuclear ARO would be increased by approximately $700 million.

In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, 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 settlement agreement, Generation has received cash reimbursements for costs incurred through April 30, 2012, totaling approximately $639 million ($543 million after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek). As of December 31, 2012, the amount of SNF storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $61 million, which is recorded within accounts receivable, other. Of this amount, $13 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities.

CENG has entered into settlement agreements with the DOE during 2011 and 2012 to recover damages caused by the DOE’s failure to comply with legal and contractual obligations to dispose of spent nuclear fuel related to the Ginna, Calvert Cliffs and Nine Mile Point nuclear power plants. At December 31, 2012, Generation had approximately $22 million recorded as a receivable from CENG with respect to costs incurred by Constellation prior to November 6, 2009, for the Nine Mile Point and Calvert Cliffs nuclear power plants. CENG received the funds for the Nine Mile Point and Calvert Cliffs settlement from the DOE in January 2013 and February 2013, respectively, and remitted the $22 million to Generation.

379

Combined Notes to Consolidated Financial Statements—(Continued)

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

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. 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, 2012, the unfunded SNF liability for the one-time fee with interest was $1,020 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, 2012, was 0.127%. 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 obligations for the Oyster Creek and TMI units remain with the former owners. Clinton has no outstanding obligation. See Note 9—Fair Value of Assets and Liabilities for additional information.

Energy Commitments

Generation’s customer facing activities include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation maintains an effective supply strategy through ownership of generation assets and power purchase and lease agreements. 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. 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. 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. In addition to physical contracts, Generation uses financial contracts for economic hedging purposes and, to a lesser extent, as part of proprietary trading 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 market participants who primarily focus on the resale of energy products for delivery. Generation provides for delivery of its energy to these customers through firm transmission.

As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase agreements with CENG were modified to be unit-contingent through the end of their original term in 2014. Under these agreements, CENG has the ability to fix the energy price on a forward basis by entering into monthly energy hedge transactions for a portion of the future sale, while any unhedged portions will be provided at market prices by default. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG’s nuclear plants at market prices. Generation discloses in the table below commitments to purchase from CENG at fixed prices. All commitments to purchase at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 22—Related Party Transactions for more details on this arrangement.

380

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2012, Generation’s short- and long-term commitments, relating to the purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following tables:


	Net Capacity Purchases ^(a)		Power-Related Purchases ^(b)		Transmission Rights Purchases ^(c)		Purchased Energy from CENG		Total
2013	$	374	$	95	$	28	$	777	$	1,274
2014		353		69		26		516		964
2015		350		25		13		—		388
2016		266		11		2		—		279
2017		203		3		2		—		208
Thereafter		469		5		34		—		508

Total	$	2,015	$	208	$	105	$	1,293	$	3,621

(a)

(b)	Power-Related Purchases include firm REC purchase agreements. The table excludes renewable energy purchases 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.

Pursuant to a PPA with Public Service Company of Oklahoma, a subsidiary of American Electric Power Company, Inc., dated as of April 17, 2009, Generation agreed to sell its rights to up to 520 MWs, 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 commenced June 1, 2012 and will run through February 28, 2022.

ComEd purchases its expected energy requirements through an ICC approved competitive bidding process administered by the IPA, existing ICC approved RFPs, and spot market purchases hedged with a financial swap contract with Generation expiring in 2013. See Note 3—Regulatory Matters for further information.

PECO’s long-term PPA with Generation, under which PECO obtained all of its electric supply from Generation for a 12-year period, expired on December 31, 2010. During 2009, 2010, 2011 and 2012, PECO entered into contracts through a competitive procurement process in order to meet a portion of its default service customers’ electric supply requirements for 2011 through 2015. See Note 3—Regulatory Matters for further information regarding the DSP Programs.

ComEd is subject to requirements established by the Illinois Settlement Legislation and the Energy Infrastructure Modernization Act related to the use of alternative energy resources. PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. BGE is subject to requirements established by the Public Utilities Article in Maryland related to the use of alternative energy resources; however, the wholesale suppliers that supply power to BGE through SOS procurement auctions have the obligation, by contract with BGE, to meet the RPS requirement. BGE has entered into contracts with curtailment services providers in accordance with the March 2009 MDPSC order. See Note 3—Regulatory Matters for additional information relating to electric generation procurement, alternative energy resources and energy efficiency programs.

381

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments as of December 31, 2012 are as follows:


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
ComEd
Electric supply procurement ^(a)	$	1,103	$	367	$	323	$	136	$	137	$	140	$	—
Renewable energy and RECs ^(b)		1,661		71		73		74		76		82		1,285
PECO
Electric supply procurement ^(c)		799		561		200		38		—		—		—
AECs		33		12		9		2		2		2		6
BGE
Electric supply procurement ^(d)		1,401		859		467		75		—		—		—
Curtailment services		153		49		47		41		16		—		—

(a)

ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 3—Regulatory Matters for additional information.

(b)

ComEd entered into 20-year contracts for renewable energy and RECs beginning June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. Per the ICC’s Final Commission Order on December 19, 2012, the quantities purchased under these long-term renewable contracts should be curtailed during the June 2013—May 2014 period to avoid exceeding the statutory rate impact for affected customers as a result of an increased number of ComEd’s customers purchasing their energy from alternative energy suppliers. See Note 3—Regulatory Matters for additional information.

(c)

PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2013 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 3—Regulatory Matters for additional information.

(d)	BGE entered into various contracts for the procurement of electricity beginning 2012 through 2015. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3—Regulatory Matters for additional information.

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). PECO and BGE have commitments to purchase natural gas, related transportation, storage capacity and services to serve customers in their gas distribution service territory. As of December 31, 2012, these net commitments were as follows:


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
Generation	$	8,857	$	1,276	$	1,207	$	1,272	$	976	$	1,064	$	3,062
PECO		444		145		87		71		49		15		77
BGE		654		133		73		54		52		52		290

382

Combined Notes to Consolidated Financial Statements—(Continued)

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

Other Purchase Obligations

The Registrants’ other purchase obligations as of December 31, 2012, which primarily represent commitments for services, materials and information technology, are as follows:


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
Exelon	$	716	$	186	$	167	$	114	$	51	$	49	$	149
Generation		487		127		120		94		32		29		85
ComEd		8		2		6		—		—		—		—
PECO		45		17		18		1		1		1		7
BGE		—		—		—		—		—		—		—

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
Letters of credit (non-debt) ^(a)	$	1,889	$	1,325	$	—	$	564	$	—	$	—	$	—
Surety bonds ^(b)		286		225		—		1		6		4		50
Performance guarantees ^(c)		1,897		908		203		—		—		—		786
Energy marketing contract guarantees ^(d)		8,556		8,556		—		—		—		—		—
Lease guarantees ^(e)		48		—		—		—		—		—		48
Middle market lending commitments ^(f)		180		180		—		—		—		—		—
Nuclear insurance premiums ^(g)		2,494		—		—		—		—		—		2,494

Total commercial commitments	$	15,350	$	11,194	$	203	$	565	$	6	$	4	$	3,378

(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.

(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c)

Performance guarantees—Guarantees issued to ensure performance under specific contracts, including $211 million issued on behalf of CENG nuclear generating facilities for credit support, $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.

(d)

Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $8.3 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $1.5 billion at December 31, 2012, which represents the total amount Exelon could be required to fund based on December 31, 2012 market prices.

(e)	Lease guarantees—Guarantees issued to ensure payments on building leases.

(f)

Middle market lending commitments—Represents commitments to investment in loans or managed funds which invest in private companies. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds. See Note 9—Fair Value of Financial Assets and Liabilities for more information on nuclear decommissioning trust funds and middle market lending.

(g)

Nuclear insurance premiums—Represents 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 the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

383

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation’s commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
Letters of credit (non-debt) ^(a)	$	1,841	$	1,278	$	—	$	563	$	—	$	—	$	—
Performance guarantees ^(b)		1,153		907		203		—		—		—		43
Energy marketing contract guarantees ^(c)		1,794		1,794		—		—		—		—		—
Middle market lending commitments ^(d)		180		180		—		—		—		—		—
Nuclear insurance premiums ^(e)		2,494		—		—		—		—		—		2,494

Total commercial commitments	$	7,462	$	4,159	$	203	$	563	$	—	$	—	$	2,537

(a)	Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.

(b)	Performance guarantees—Guarantees issued to ensure performance under specific contracts including $211 million issued on behalf of CENG nuclear generating facilities for credit support.

(c)

Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.5 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.6 billion at December 31, 2012, which represents the total amount Generation could be required to fund based on December 31, 2012 market prices.

(d)

(e)

Nuclear insurance premiums—Represents 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.

ComEd’s commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
Letters of credit (non-debt) ^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)		8		8		—		—		—		—		—
Performance guarantees ^(c)		200		—		—		—		—		—		200

Total commercial commitments	$	230	$	30	$	—	$	—	$	—	$	—	$	200

(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)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c)	Reflects full and unconditional guarantees of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.

384

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO’s commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
Letters of credit (non-debt) ^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)		3		3		—		—		—		—		—
Performance guarantees ^(c)		178		—		—		—		—		—		178

Total commercial commitments	$	203	$	25	$	—	$	—	$	—	$	—	$	178

(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)	Reflects full and unconditional guarantees of Trust Preferred Securities of PECO Trust III and IV, which is a 100% owned finance subsidiary of PECO.

BGE’s commercial commitments as of December 31, 2012, representing commitments potentially triggered by future events, were as follows


			Expiration within
	Total		2013		2014		2015		2016		2017		2018 and beyond
Letters of credit (non-debt) ^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)		2		2		—		—		—		—		—
Performance guarantees ^(c)		250		—		—		—		—		—		250

Total commercial commitments	$	254	$	4	$	—	$	—	$	—	$	—	$	250

(a)	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b)	Surety bond—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c)	Reflects full and unconditional guarantees of Trust Preferred Securities of BGE Capital Trust II which is a 100% owned finance subsidiary of BGE.

Construction Commitments

Generation has committed to the construction of a solar PV facility in Los Angeles County, California. The first portion of the project began operations in December 2012, with additional phases to come online and an expectation of full commercial operation by the end of the third quarter of 2013. Generation’s estimated remaining commitment for the project is $636 million for 2013. See Note 4—Merger and Acquisitions for additional information.

Refer to Note 3—Regulatory Matters for information on investment programs associated with regulatory mandates, such as ComEd’s Infrastructure Investment Plan under EIMA, PECO’s Smart Meter Procurement and Installation Plan, BGE’s comprehensive smart grid initiative and ComEd’s, PECO’s and BGE’s commitment to construct transmission facilities under their operating agreements with PJM.

Constellation Merger Commitments

Exelon’s commercial and construction commitments shown above do not include the merger commitments made to the State of Maryland in conjunction with the Constellation merger. See Note 4—Merger and Acquisitions for additional information on the merger commitments.

385

Combined Notes to Consolidated Financial Statements—(Continued)

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

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2012 were:


	Exelon			Generation			ComEd ^(b)		PECO ^(b)		BGE ^(b)(c)
2013	$	88		$	38		$	13	$	14	$	12
2014		83			38			11		13		10
2015		73			38			11		3		9
2016		69			36			11		3		7
2017		63			36			6		3		6
Remaining years		488			367			57		—		29

Total minimum future lease payments	$	864	^(a)	$	553	^(a)	$	109	$	36	$	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, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s annual obligation for these arrangements, included in each of the years 2013—2017, was $1 million. PECO’s annual obligation for these agreements, included in each of the years 2013—2017, was $3 million. BGE’s annual obligation for these agreements, included in each of the years 2013—2017, was $1 million.

(c)	Includes all future lease payments on a 99 year real estate lease that expires in 2105.

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2012, 2011 and 2010:


For the Year Ended December 31,	Exelon		Generation ^(a)		ComEd		PECO		BGE
2012	$	930	$	872	$	18	$	27	$	12
2011		711		659		18		28		15
2010		722		665		19		31		13

(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 $801 million, $630 million and $641 million during 2012, 2011 and 2010, respectively.

For information regarding capital lease obligations, see Note 11—Debt and Credit Agreements.

Indemnifications Related to Sale of 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).

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, 2012. Generation believes that it is remote that it will be required to make any additional payments under the guarantee, and currently has no recorded liabilities associated with this guarantee. Generation expects that the exposure covered by this guarantee will expire in 2014. The guarantee is included above in the Commercial Commitments table under performance guarantees.

386

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 as of December 31, 2012. Generation believes that it is remote that it will be required to make payments under the guarantee, and has not recorded a liability associated with this guarantee. The exposures covered by this guarantee expired in part during 2008. Generation expects that the remaining exposure will expire in 2013. The guarantee of $95 million is included above in the Commercial Commitments table under performance guarantees.

Environmental Matters

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. 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, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For many of these sites, ComEd, PECO or BGE is one of several PRPs that may be responsible for ultimate remediation of each location.

•

ComEd has identified 42 sites, 13 of which have been approved for cleanup by the Illinois EPA or the U.S. EPA and 27 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2016.

•

PECO has identified 26 sites, 16 of which have been approved for cleanup by the PA DEP and 10 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2019.

•

BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. One gas purification site is in the initial stages of investigation at the direction of the MDE.

Pursuant to orders from the ICC, PAPUC and MDPSC, respectively, ComEd, PECO and BGE are authorized to and are currently recovering environmental costs for the remediation of former MGP facility sites from customers, for which they have recorded regulatory assets. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC,

387

Combined Notes to Consolidated Financial Statements—(Continued)

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

are recovering environmental remediation costs of the MGP sites through a provision within customer rates. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. During the second and third quarters of 2012, ComEd and PECO completed annual studies 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 $146 million and $7 million, respectively. BGE assessed its currently and formerly owned gas manufacturing and purification sites quarterly in 2012 and determined that a loss was not probable at ten of its sites as of December 31, 2012. As discussed above, the remediation costs at two of BGE’s MGP sites are not considered material. Furthermore, an estimate of a range of possible loss, if any, related to BGE’s gas purification site under investigation cannot be determined as of December 31, 2012 given that the site is in the early stages of investigation and any potential contamination is currently unknown. See Note 3—Regulatory Matters for additional information regarding the associated regulatory assets.

This historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs based on probabilistic and deterministic modeling using all available information at the time of each study and the remediation standards currently required by the U.S. EPA. The increase in the reserve at ComEd was predominately tied to 6 sites with a total increase of approximately $111 million. The change was driven by the completion of additional preliminary environmental investigations that identified increases in scope for the remediation of larger areas and to greater depths, along with the requirement for additional groundwater management not previously contemplated in prior studies. ComEd also obtained new information on scope requirements for several sites where another PRP is leading remediation efforts and that ComEd shares responsibility. Prior to completion of any significant clean up, each site remediation plan is approved by the Illinois EPA.

As of December 31, 2012 and 2011, the Registrants have accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:


December 31, 2012	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	338	$	298
Generation		30		—
ComEd		260		254
PECO		47		44
BGE		1		—

December 31, 2011	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	224	$	168
Generation		47		—
ComEd		127		121
PECO		50		47
BGE		—		—

388

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

Water Quality

Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s and CENG’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. For Generation, those facilities are Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna.

On March 28, 2011, the U.S. EPA issued the proposed regulation under Section 316(b). The proposal does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The proposed rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or similar technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry.

In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so-called “non-use” benefits of the rule. Exelon filed comments for each NODA, supporting the additional flexibility afforded by the impingement NODA, and opposing the NODA relating to calculation of non-use benefits due to its inaccurate and unreliable methodologies that would artificially inflate the benefits of proposed technologies that would otherwise not be cost-effective. On July 18, 2012, the U.S. EPA announced that it had agreed to extend the court approved Settlement Agreement to extend the deadline to issue a final rule until June 27, 2013. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment.

Oyster Creek. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would have required, in the exercise of its best professional judgment, the installation of cooling towers as the best technology available within seven years after the effective date of the permit. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek no later than December 31, 2019. The current NRC license for Oyster Creek expires in 2029. In reliance upon Exelon’s determination to cease generation operations no later than December 31, 2019, the NJDEP determined that closed cycle cooling is not the best technology

389

Combined Notes to Consolidated Financial Statements—(Continued)

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

available for Oyster Creek given the length of time that would be required to retrofit from the existing once-through cooling system to a closed-cycle cooling system and the limited life span of the plant after installation of a closed-cycle cooling system. Based on its consideration of these and other factors, NJDEP determined that the existing measures at the plant represent the best technology available for the facility’s cooling water intake through cessation of generation operations.

On December 9, 2010, Generation executed an Administrative Consent Order (ACO) with the NJDEP regarding Oyster Creek. The ACO sets forth, among other things, the agreement by Generation to permanently cease generation operations at Oyster Creek if the conditions of the ACO are satisfied. In accordance with the ACO, on December 21, 2011, the NJDEP agreed to issue a final NPDES permit that became effective on April 12, 2012 that does not require the construction of cooling towers or other closed-cycle cooling facilities. The ACO and the final permit apply only to Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance requirements for Section 316(b) at Exelon’s other plants.

As a result of the decision and the ACO, the expected economic useful life of Oyster Creek was reduced by 10 years to correspond to Exelon’s current best estimate as to the timing of ceasing generation operations at the Oyster Creek unit in 2019. The financial impacts relate primarily to accelerated depreciation and accretion expense associated with the changes in decommissioning assumptions related to Generation’s asset retirement obligation over the remaining expected economic useful life of Oyster Creek.

Salem and Other Power Generation Facilities. In June 2001, the NJDEP issued a renewed NPDES 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 NPDES permit while the NPDES 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 $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment.

It is unknown at this time whether the NJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation’s other power generation facilities, as well as CENG’s, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation and CENG.

Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG’s generating facilities and its future results of operations, cash flows and financial position.

390

Combined Notes to Consolidated Financial Statements—(Continued)

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

Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Prior to the merger, Constellation recorded a liability in its Consolidated Balance Sheets of approximately $23 million to comply with the consent decree. The remaining liability as of December 31, 2012, is approximately $3 million. In addition, a private party has asserted claims relating to groundwater contamination. The company believes that these claims are without merit and is vigorously contesting them.

Alleged Conemaugh Clean Streams Act Violation. The PA DEP has alleged that GenOn Northeast Management Company (GenOn), the operator of Conemaugh Generating Station, violated the Pennsylvania Clean Streams Law. GenOn reached agreement with PA DEP on a proposed Consent Order that was approved by the Commonwealth Court of Pennsylvania on December 4, 2012. Under the Consent Order, GenOn is obligated to pay a civil penalty of $0.5 million, of which Generation’s responsibility is approximately $0.2 million.

Air Quality

Cross-State Air Pollution Rule (CSAPR). 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 NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court’s July 11, 2008 opinion. On July 7, 2011, the U.S. EPA published the final rule, known as the CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states.

Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court’s consideration of the matter on the merits. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR in the interim. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA has exceeded its authority in certain material aspects of the CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. On January 24, 2013, the Court denied petitions for reconsideration of the ruling by the three-judge panel.

Under the CSAPR, Generation units were to receive allowances based on historic heat input, and intrastate and limited interstate trading of allowances was permitted. The CSAPR restricted entirely the use of pre-2012 allowances. Existing SO₂ allowances under the ARP would remain available for use under ARP. During the third quarter of 2010, Generation recognized a lower of cost or market impairment charge of $57 million on its ARP SO₂ allowances that were not expected to be used by Generation’s fossil-fuel power plants and that had not been sold forward. The impairment was recorded due to the significant decline of allowance market prices because CSAPR regulations would restrict entirely the use of ARP SO₂ allowances beginning in 2012. As of December 31, 2012, Generation had $45 million of emission allowances carried at the lower of weighted average cost or market.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

EPA Mercury and Air Toxics Standards (MATS). The MATS rule became final on April 16, 2012. The MATS rule reduces emissions of toxic air pollutants, and finalized the new source performance standards for fossil fuel-fired electric utility steam generating units (EGUs). The MATS rule requires coal-fired EGUs to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the required standards may need to upgrade existing controls or add new controls to comply. In addition, the new standards will cause oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies or retire the units. The MATS rule requires generating stations to meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in limited cases. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon was granted permission by the Court to intervene in support of the rule. A decision by the Court is not expected until sometime in 2013. The outcome of the appeal, and its impact on power plant operators’ investment and retirement decisions, is uncertain.

Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS.

In addition, as of December 31, 2012, Exelon had a $693 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material.

National Ambient Air Quality Standards (NAAQS). The U.S. EPA previously announced that it would complete a review of the NAAQS by 2014. In December 2012, the U.S. EPA issued a more stringent particulate matter NAAQS. The Agency is currently evaluating its 2008 ozone NAAQS for potentially more stringent requirements as was previously recommended by the U.S. EPA Clean Air Act Scientific Advisory Committee (CASAC) when it reviewed the 2008 ozone NAAQS (that is currently the subject of litigation in the D.C. Circuit Court). These final and pending NAAQS reviews could result in more stringent emissions limits on fossil-fired electric generating stations. In July 2012, the D.C. Circuit Court issued separate rules upholding tightened NAAQS established by the U.S. EPA in 2010 for nitrogen dioxide and sulfur dioxide. The rulings clear the way for the U.S. EPA to continue work already underway with state and local agencies on implementing revised SIP’s designed to achieve or maintain the required air quality levels. To the extent not already impacted by CAIR (and in the future by CSAPR after revision upon remand) and MATS, some power plants could be required to achieve further reductions of nitrogen dioxide and sulfur dioxide emissions.

In September 2011, the U.S. EPA withdrew its reconsideration of the NAAQS standard for ozone, which is next scheduled for reconsideration in 2014. Litigation of the ozone standard in the D.C. Circuit Court continues. In December 2012, the U.S. EPA issued its final revisions to the Agency’s particulate matter (PM) NAAQS. In its final rule, the U.S. EPA lowered the annual PM2.5 standard, but declined to issue a new secondary NAAQS to improve urban visibility. The U.S. EPA indicated in its final rule that by 2020 it expects most areas of the country will be in attainment of the new PM2.5 NAAQS based on

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Combined Notes to Consolidated Financial Statements—(Continued)

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

currently expected regulations, such as the MATS regulation. It is unclear if the vacatur of the CSAPR, one of the regulations that the U.S. EPA is relying on to assist with future PM reduction, would alter the U.S. EPA’s view since either CAIR or a finalized CSAPR regulation would be in effect leading up to 2020.

In addition to these NAAQS, the U.S. EPA also expects to finalize initial designations for the 2010 one-hour SO₂ standard in June 2013 and require states to submit state implementation plans (SIPs) for nonattainment areas by February 2015. Compliance with the one-hour SO₂ standard is required by February 2018. While significant SO₂ reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the U.S. EPA’s final one-hour SO₂ standard designation methodology at this point in time as the U.S. EPA continues to consider whether to used modeled or monitored data to inform the designation process, nor potential SIP requirements for areas found to be in nonattainment.

Notices and Finding of Violations and Midwest Generation Bankruptcy. In December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance by the stations with environmental laws before their purchase 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, including its rights and obligations under the sale agreement with Midwest Generation and EME.

On August 6, 2007, ComEd received a NOV addressed to it and Midwest Generation from the U.S. EPA, alleging, in relevant part, that ComEd and Midwest Generation violated and are continuing to violate provisions of the 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 their purchase from ComEd in 1999. In August 2009, the United States and the State of Illinois filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to most of the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon was named as a defendant in this original complaint. In March 2010, the District Court granted Midwest Generation’s partial motion to dismiss all but one of the claims against Midwest Generation. The District Court held that Midwest Generation cannot be liable for any alleged violations relating to construction that occurred prior to Midwest Generation’s ownership of the stations. In May 2010, the government plaintiffs filed an amended complaint against Midwest Generation asserting claims substantially similar to those in the original complaint, and added ComEd and EME as defendants. The amended complaint seeks injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertain to ComEd. On March 16, 2011, the District Court granted ComEd’s motion to dismiss the May 2010 complaint in its entirety as it relates to ComEd. On January 3, 2012, upon leave of the District Court, the government parties appealed the dismissal of ComEd to the U.S. Circuit Court of Appeals for the Seventh Circuit. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the amended complaint, however, Exelon, Generation and ComEd have concluded that, in light of the March 2011 District Court decision, the likelihood of loss is remote. Therefore, no reserve has been established.

393

Combined Notes to Consolidated Financial Statements—(Continued)

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

On December 17, 2012, EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code (the “Petition Date”).

As a result of the bankruptcy filing, Exelon and Generation have recorded liabilities and receivable reserves as of December 31, 2012, for a total of $13 million, which consists primarily of lease payments under a coal rail car lease and estimated payments for asbestos personal injury claims filed pre-Petition Date. The Bankruptcy Court approved the rejection of the agreement under which Midwest Generation was responsible for obligations under the lease, leaving Generation as the party responsible to make remaining payments under the lease. Exelon and Generation currently expect Midwest Generation or its successor will remain responsible for asbestos personal injury claims filed post-Petition Date, and as such have recorded no liability for such amounts. Requirements for Generation to ultimately satisfy such claims could have a material adverse impact on Exelon’s and Generation’s future results of operations.

As of the Petition Date, Generation had wholesale power transactions with Edison Mission Marketing and Trading, an affiliate of Midwest Generation not included in the bankruptcy proceeding. Generation expects these transactions to be fully settled in the normal course.

Certain environmental laws and regulations subject current and prior owners of properties or generators of hazardous substances at such properties to liability for remediation costs of environmental contamination. As a prior owner of the generating stations, ComEd (and Generation, through its agreement in the 2001 restructuring to assume ComEd’s rights and obligations associated with its former generation business) could face liability (along with any other potentially responsible parties) for environmental conditions requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors, including the impact of Midwest Generation’s bankruptcy. Additionally, the obligations of EME and Midwest Generation to ComEd under the sale agreement, including the environmental indemnity, may be discharged in the bankruptcy proceeding. In such circumstances, ComEd (and Generation, through ComEd) may only have an unsecured claim against EME and Midwest Generation for the environmental remediation costs that would have otherwise been obligations of EME and Midwest Generation under the sale agreement. This unsecured claim may yield a fractional, or possibly no, recovery for ComEd and Generation.

ComEd and Generation continue to monitor the bankruptcy proceedings and available public information as to potential environmental exposures regarding the Midwest Generation plant sites. Midwest Generation publicly disclosed in its third quarter 2012 Form 10-Q that (i) it has accrued a probable amount of approximately $9 million for estimated environmental investigation and remediation costs under CERCLA, or similar laws, for the investigation and remediation of contaminated property at four Midwest Generation plant sites, (ii) it has identified stations for which a reasonable estimate for investigation and/ or remediation cannot be made and (iii) it and the Illinois EPA entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Powerton, Joliet, Will County and Waukegan generating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihood or magnitude of any such exposures. Further, Midwest Generation’s reorganization process will likely extend beyond one year and the outcome is uncertain, including whether the facilities will continue to operate and the identity or financial wherewithal of potential future plant owners. For these reasons, ComEd and Generation are unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to the generating stations, and no liability has been recorded at December 31, 2012. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverse impact on their future results of operations and cash flows.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Solid and Hazardous Waste

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 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. 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 approximately $42 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 U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the U.S. EPA for review. In June 2012, the U.S. EPA requested that the PRPs perform additional analysis and groundwater sampling as part of the SFS that could take up to one year to complete, and it is unknown when the U.S. EPA will propose a remedy for public comment. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRP’s to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require a complete excavation remedy is remote.

On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2013 so that settlement discussions could proceed. Based on Exelon’s preliminary review, it appears probable that Exelon has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.

On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants, respectively, including Exelon, Generation and ComEd (the “Exelon defendants”). The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the defendants’ negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filed voluntary motions to dismiss the Exelon defendants from both lawsuits which was subsequently granted. On October 23, 2012, a third lawsuit was filed in the same court on behalf of three additional plaintiffs against Cotter and seven other defendants, but not Exelon. The allegations in that complaint mirror the two previously-filed lawsuits. It is reasonably possible that Exelon would be

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Combined Notes to Consolidated Financial Statements—(Continued)

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

considered liable due to its indemnification responsibilities of Cotter described above. Due to the early stage of the litigation, Exelon cannot estimate a range of loss, if any.

68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The potentially responsible parties submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. The U.S. EPA is expected to make a final selection of one of the alternatives in 2013. Based on Exelon’s preliminary review, it appears probable that Exelon has liability and has established an appropriate accrual for its share of the estimated clean-up costs. BGE is indemnified by a wholly owned subsidiary of Generation for most of the costs related to this settlement and clean-up of the site.

Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, MD. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. The letter provided 60 days for the PRPs to decide whether or not to participate in the investigation. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On July 30, 2012, BGE along with the three other named PRP’s provided the U.S. EPA with a “Good Faith Offer” along with a proposed Settlement Agreement to conduct a Remedial Investigation and a Feasibility Study at the Site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The PRPs will seek to reach agreement with the U.S. EPA to conduct the investigation. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE’s reasonably possible loss, if any, cannot be determined.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the Federal, regional and state levels. 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. Consequently, 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 on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do 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 has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations (the Tailoring Rule) relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO₂ equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO₂ equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On July 2, 2012, the

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Combined Notes to Consolidated Financial Statements—(Continued)

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

U.S. EPA declined to lower GHG permit thresholds in its final “Step 3” Tailoring Rule update. The U.S. EPA will review permit thresholds again in a 2015 rulemaking process. On June 26, 2012, the United States Court of Appeals for the District of Columbia, in a per curium decision, dismissed industry and state petitions challenging the U.S. EPA’s Tailoring Rule based on petitioners’ lack of standing. Further, in the same decision, the court denied all challenges to the U.S. EPA’s endangerment finding, and the Agency’s “Tailpipe Rule” for cars and light trucks. In August 2012, several industry parties filed petitions for an en banc rehearing of the Agency’s GHG regulations with the D.C. Circuit court. On September 6, 2012, the Circuit Court ordered the U.S. EPA, intervening groups, and some states to reply to the industry petitions.

On April 13, 2012, the U.S. EPA published proposed regulations for NSPS for GHG emissions from new fossil fuel power plants, greater than 25 MW, that would require the plants to limit CO₂ emissions to a thirty year average of less than 1,000 pounds per MWh (less than 1,800 pounds per MWh for the first ten years and less than 600 pounds per MWh thereafter). Under the PSD regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case by case basis. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants. The U.S. EPA is also expected to establish in 2013 GHG emission regulations for existing stationary sources under Section 111(d) of the Clean Air Act.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon, Generation and BGE).

Exelon and Generation. 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.

At December 31, 2012 and 2011, Generation had reserved approximately $63 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2012, approximately $14 million of this amount related to 170 open claims presented to Generation, while the remaining $49 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050 based on actuarial assumptions and analyses, 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 the second quarter of 2012, Generation increased its reserve by approximately $19 million, primarily due to increased actual and projected number and severity of claims. During 2011 and 2010, the updates to this reserve did not result in material adjustments.

BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.

Approximately 480 individuals who were never employees of BGE or Generation have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and Generation in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or Generation and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Discovery begins in these cases once they are placed on the trial docket. At present, none of the pending cases are set for trial. Given the limited discovery, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include:

•

the identity of the facilities at which the plaintiffs allegedly worked as contractors;

•

the names of the plaintiffs’ employers;

•

the dates on which and the places where the exposure allegedly occurred; and

•

the facts and circumstances relating to the alleged exposure.

Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

Federal Energy Regulatory Commission Investigation (Exelon and Generation).

On January 30, 2012, FERC published a notice on its website regarding a non-public investigation of certain of Constellation’s power trading activities in and around the ISO-NY from September 2007 through December 2008. Prior to the merger, Constellation announced on March 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay a $135 million civil penalty and $110 million in disgorgement. The disgorgement amount will be disbursed in two ways. First, Constellation will provide $1 million each to six U.S. regional grid operators for the purpose of improving their surveillance and analytic capabilities. The remainder of the disgorgement amount was deposited in a fund that will be administered by a FERC ALJ. State agencies in New York, New England and PJM (the regional grid operator for 13 states and the District of Columbia) will be eligible to make claims against the fund on behalf of electric energy consumers in those states.

During the year ended December 31, 2012, Generation recorded expense of $195 million in operating and maintenance expense with the remaining $50 million recorded as a Constellation pre-acquisition contingency. As of December 31, 2012, the full amount of the civil penalty and disgorgement was paid. See Note 4—Merger and Acquisitions for additional information on the merger.

Continuous Power Interruption (ComEd)

The Illinois Public Utilities Act 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) more than 30,000 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.

On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd’s service territory, as well as for five other storm systems that affected ComEd’s customers during June and July 2011 (Summer 2011 Storm Docket). The ICC is currently conducting a proceeding to assess

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Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd’s request. In the absence of a favorable determination from the ICC, some ComEd customers affected by the outages could seek recovery of their actual, non-consequential damages, and the local governments in the areas in which those customers are located could seek recovery of emergency and contingency expenses.

On January 25, 2013 the ALJ issued a Proposed Order in the Summer 2011 Storm Docket. The ALJ found that a complete waiver of liability should apply for five of the six storms at issue, and found that for the July 2011 storm, 34,599 interruptions were preventable and therefore no waiver should apply. The ALJ also found that ComEd’s system is designed, constructed and maintained in accordance with good utility practice, thereby rejecting a request by the Illinois Attorney General for the ICC to open an investigation.

In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (February 2011 Blizzard Docket). On January 10, 2013, the ALJ issued a Proposed Order in the February 2011 Blizzard Docket, finding that a complete waiver of liability should apply for the storm. As with the Summer 2011 Storm Docket, the ALJ found that ComEd’s system is designed, constructed and maintained in accordance with good utility practice.

The ultimate outcomes of these proceedings are uncertain, and the amount of damages, if any, which might be asserted, cannot be reasonably estimated at this time, but may be material to ComEd’s results of operations and cash flows.

Securities Class Action (Exelon)

Three federal securities class action lawsuits were filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008 against Constellation. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation, a number of its former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation’s June 27, 2008 offering of the Debentures. The securities class actions also allege that Constellation issued false or misleading statements or was aware of material undisclosed information which contradicted public statements, including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

The Southern District of New York granted the defendants’ motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Exchange Act of 1934 and limiting the suit to those persons who purchased Debentures in

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Combined Notes to Consolidated Financial Statements—(Continued)

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

the June 2008 offering. In August 2011, plaintiffs requested permission from the court to file a third amended complaint in an effort to attempt to revive the claims of the common shareholders. Constellation filed an objection to the plaintiffs’ request for permission to file a third amended complaint and, on March 28, 2012, the District Court of Maryland denied the plaintiffs’ request for permission to revive the claims of the common shareholders. Given that limited discovery has occurred, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims, Exelon is unable at this time to provide an estimate of the range of reasonably possible loss relating to these proceedings or to determine the ultimate outcome of the securities class actions or their possible effect on its financial results.

Fund Transfer Restrictions (Exelon, ComEd, PECO and BGE)

Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

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’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, 2012, such capital was $3.0 billion and amounted to about 34 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.

400

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE pays dividends on its common stock after its Board of Directors declares them. However, BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE’s preference stock have not been paid.

General (Exelon, Generation, ComEd, PECO and BGE).

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Income Taxes

See Note 12—Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

20. Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010.


For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO			BGE
Taxes other than income
Utility ^(a)	$	463	$	82	$	239	$	141		$	75
Property		227		189		22		13			111
Payroll		131		78		26		12			18
Other		198		20		8		(4	)		4

Total taxes other than income	$	1,019	$	369	$	295	$	162		$	208

401

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	443	$	27	$	243	$	173	$	79
Property		177		146		22		9		107
Payroll		123		71		25		13		17
Other		42		20		6		10		4

Total taxes other than income	$	785	$	264	$	296	$	205	$	207


For the Year Ended December 31, 2010	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	476	$	—	$	205	$	271	$	79
Property		175		142		20		13		102
Payroll		121		70		24		12		16
Other		36		18		7		7		3

Total taxes other than income	$	808	$	230	$	256	$	303	$	200

(a)

Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations.


For the Year Ended December 31, 2012	Exelon			Generation			ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory Agreement Units	$	189		$	189		$	—	$	—	$	—
Non-Regulatory Agreement Units		102			102			—		—		—
Net unrealized gains on decommissioning trust funds—
Regulatory Agreement Units		386			386			—		—		—
Non-Regulatory Agreement Units		105			105			—		—		—
Net unrealized gains on pledged assets—
Zion Station decommissioning		73			73			—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)		(530	)		(530	)		—		—		—

Total decommissioning-related activities		325			325			—		—		—

Investment income		20			3			1		2		11	^(c)
Long-term lease income		29			—			—		—		—
Interest income related to uncertain income tax positions		15			2			20		—		—
AFUDC-Equity		17			—			6		4		10
Credit facility termination fees		(85	)		(85	)		—		—		—
Other		25			(6	)		12		2		2

Other, net	$	346		$	239		$	39	$	8	$	23

402

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2011	Exelon			Generation			ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory Agreement Units	$	177		$	177		$	—	$	—	$	—
Non-Regulatory Agreement Units		45			45			—		—		—
Net unrealized losses on decommissioning trust funds—
Regulatory Agreement Units		(74	)		(74	)		—		—		—
Non-Regulatory Agreement Units		(4	)		(4	)		—		—		—
Net unrealized gains on pledged assets—
Zion Station decommissioning		48			48			—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)		(130	)		(130	)		—		—		—

Total decommissioning-related activities		62			62			—		—		—

Investment income		10			1			1		3		13	^(c)
Long-term lease income		28			—			—		—		—
Interest income related to uncertain income tax positions		53			31			14		1		—
AFUDC-Equity		17			—			8		9		15
Bargain purchase gain related to Wolf Hollow acquisition		36			36			—		—		—
Other		(3	)		(8	)		6		1		(2	)

Other, net	$	203		$	122		$	29	$	14	$	26


For the Year Ended December 31, 2010	Exelon			Generation			ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory Agreement Units	$	176		$	176		$	—	$	—	$	—
Non-Regulatory Agreement Units		51			51			—		—		—
Net unrealized gains on decommissioning trust funds—
Regulatory Agreement Units		316			316			—		—		—
Non-Regulatory Agreement Units		104			104			—		—		—
Regulatory offset to decommissioning trust fund-related activities ^(b)		(394	)		(394	)		—		—		—

Total decommissioning-related activities		253			253			—		—		—

Investment income		1			—			—		1		15	^(c)
Long-term lease income		27			—			—		—		—
Interest income related to uncertain income tax positions		—			—			6		—		—
AFUDC-Equity		11			—			4		7		10
Realized gain on Rabbi trust investments		1			—			1		—		—
Other		19			4			13		—		—

Other, net	$	312		$	257		$	24	$	8	$	25

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 13—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(c)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 – Regulatory Matters for additional information regarding the rate stabilization deferral.

403

Combined Notes to Consolidated Financial Statements—(Continued)

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

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010.


For the Year Ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,712	$	733	$	525	$	207	$	245
Regulatory assets		129		—		80		10		53
Amortization of intangible assets, net		40		35		5		—		—
Amortization of energy contract assets and liabilities ^(a)		1,110		1,110		—		—		—
Nuclear fuel ^(a)		848		848		—		—		—
ARO accretion ^(b)		240		240		—		—		—

Total depreciation, amortization and accretion	$	4,079	$	2,966	$	610	$	217	$	298


For the Year Ended December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,284	$	570	$	502	$	191	$	224
Regulatory assets		63		—		52		11		50
Nuclear fuel ^(a)		755		755		—		—		—
ARO accretion ^(b)		214		214		—		—		—

Total depreciation, amortization and accretion	$	2,316	$	1,539	$	554	$	202	$	274


For the Year Ended December 31, 2010	Exelon		Generation		ComEd		PECO			BGE
Depreciation, amortization and accretion
Property, plant and equipment	$	1,144	$	474	$	473	$	171		$	214
Regulatory assets		931		—		43		889	^(c)		35
Nuclear fuel ^(a)		672		672		—		—			—
ARO accretion ^(b)		196		195		1		—			—

Total depreciation, amortization and accretion	$	2,943	$	1,341	$	517	$	1,060		$	249

(a)	Included in revenues or fuel expense on the Registrants’ Consolidated Statements of Operations.

(b)	Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.

(c)	For PECO, primarily reflects CTC amortization.

404

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2012	Exelon			Generation			ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	761		$	286		$	288		$	113		$	136
Income taxes (net of refunds)		(171	)		175			(42	)		(64	)		(112	)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	820		$	341		$	282		$	50		$	57
Loss in equity method investments		91			91			—			—			—
Provision for uncollectible accounts		164			22			42			60			44
Provision for obsolete inventory		6			6			1			—			—
Stock-based compensation costs		94			—			—			—			—
Other decommissioning-related activity ^(a)		(145	)		(145	)		—			—			—
Energy-related options ^(b)		160			160			—			—			—
Amortization of regulatory asset related to debt costs		18			—			13			3			2
Amortization of rate stabilization deferral		57			—			—			—			67
Amortization of debt fair value adjustment		(34	)		(34	)		—			—			—
Merger-related commitments ^(d)		141			32			—			—			27
Severance cost		99			34			—			—			—
Discrete impacts from Energy Infrastructure Modernization Act (EIMA) ^(c)		(96	)		—			(96	)		—			—
Amortization of debt costs		19			11			5			3			2
Other		(11	)		19			5			9			(6	)

Total other non-cash operating activities	$	1,383		$	537		$	252		$	125		$	193

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	71		$	—		$	28		$	20		$	26
Other regulatory assets and liabilities		(404	)		—			(68	)		18			(112	)
Other current assets		213			(30	)		(7	)		(12	)		(7	)
Other noncurrent assets and liabilities		(248	)		(98	)		(95	)		(10	)		8

Total changes in other assets and liabilities	$	(368	)	$	(128	)	$	(142	)	$	16		$	(85	)


	Exelon		Generation			ComEd		PECO		BGE
Non-cash investing and financing activities:
Change in ARC	$	781	$	781		$	2	$	—	$	—
Change in capital expenditures not paid		160		103	^(e)		15		26		(4	)
Merger with Constellation, common stock issued		7,365		5,264			—		—		—

(a)

Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 13—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b)	Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(c)

Includes the regulatory asset, pursuant to EIMA, which represents the ICC’s approved distribution formula and associated rulings as of December 31, 2012 and ComEd’s best estimate of the probable increase in distribution rates to provide recovery of prudent and reasonable costs incurred for the 12 months ended December 31, 2012.

(d)	See Note 4—Mergers and Acquisitions for more information on merger-related commitments.

(e)	Includes $247 million of capital expenditures not paid as of December 31, 2012 related to Antelope Valley.

405

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2011	Exelon			Generation			ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	649		$	158		$	296		$	128		$	122
Income taxes (net of refunds)		(457	)		347			(676	)		(65	)		(54	)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	542		$	249		$	213		$	32		$	51
Provision for uncollectible accounts		121			—			57			64			44
Stock-based compensation costs		67			—			—			—			—
Other decommissioning-related activity ^(a)		16			16			—			—			—
Energy-related options ^(b)		137			137			—			—			—
Amortization of regulatory asset related to debt costs		21			—			18			3			2
Amortization of rate stabilization deferral		—			—			—			—			57
Deferral of storm costs		—			—			—			—			(16	)
Uncollectible accounts recovery, net		14			—			14			—			—
Discrete impacts from 2010 Rate Case order ^(c)		(32	)		—			(32	)		—			—
Bargain purchase gain related to Wolf Hollow Acquisition		(36	)		(36	)		—			—			—
Discrete impacts from Energy Infrastructure Modernization Act (EIMA) ^(d)		(82	)		—			(82	)		—			—
Other		2			55			(4	)		1			(9	)

Total other non-cash operating activities	$	770		$	421		$	184		$	100		$	129

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(45	)	$	—		$	(49	)	$	4		$	(52	)
Other regulatory assets and liabilities		—			—			44			26			10
Other current assets		(101	)		(23	)		(14	)		(12	)		(88	)
Other noncurrent assets and liabilities		122			(34	)		64			(4	)		(31	)

Total changes in other assets and liabilities	$	(24	)	$	(57	)	$	45		$	14		$	(161	)


	Exelon		Generation			ComEd		PECO			BGE
Non-cash investing and financing activities:
Change in ARC	$	186	$	186		$	—	$	—		$	—
Change in capital expenditures not paid		96		125	^(e)		7		(35	)		(7	)

(a)

(b)	Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(c)	In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan. See Note 3—Regulatory Matters for more information.

(d)

Includes the establishment of a regulatory asset, pursuant to EIMA, for the 2011 annual reconciliation in ComEd’s distribution formula rate tariff and the deferral of costs associated with significant 2011 storms, partially offset by an accrual to fund a new Science and Technology Innovation Trust. See Note 3—Regulatory Matters for more information.

(e)	Includes $120 million of capital expenditures not paid as of December 31, 2011 related to Antelope Valley.

406

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2010	Exelon			Generation			ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	665	^(a)	$	145		$	283		$	168		$	128
Income taxes (net of refunds)		1,219			732			15			433			(76	)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	581		$	268		$	215		$	46		$	48
Provision for uncollectible accounts		108			1			48			59			38
Provision for obsolete inventory		12			12			—			—			—
Stock-based compensation costs		44			—			—			—			—
Other decommissioning-related activity ^(b)		(91	)		(91	)		—			—			—
Energy-related options ^(c)		(73	)		(73	)		—			—			—
ARO adjustment		(19	)		(8	)		(10	)		(1	)		—
Amortization of regulatory asset related to debt costs		24			—			20			4			2
Amortization of rate stabilization deferral		—			—			—			—			62
Accrual for Illinois utility distribution tax refund ^(d)		(25	)		—			(25	)		—			—
Under-recovered uncollectible accounts, net ^(e)		(14	)		—			(14	)		—			—
ARP SO2 allowances impairment		57			57			—			—			—
Other		5			16			4			—			(6	)

Total other non-cash operating activities	$	609		$	182		$	238		$	108		$	144

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	61		$	—		$	58		$	3		$	6
Other regulatory assets and liabilities		—			—			(19	)		35			(64	)
Other current assets		(18	)		(16	)		12			(19	)		(7	)
Other noncurrent assets and liabilities		(99	)		(29	)		(184	)^(f)		59			2

Total changes in other assets and liabilities	$	(56	)	$	(45	)	$	(133	)	$	78		$	(63	)


	Exelon			Generation			ComEd			PECO			BGE
Non-cash investing and financing activities:
Change in ARC	$	(428	)	$	(428	)	$	—		$	—		$	—
Change in capital expenditures not paid		34			13			7			14			28
Purchase accounting adjustments		9			9			—			—			—
Exelon Wind acquisition ^(g)		32			32			—			—			—

(a)	Excludes $167 million of interest paid to the IRS relating to a preliminary agreement reached during the third quarter of 2010. See Note 12—Income Taxes for addition information.

(b)

(c)	Includes amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of underlying transactions.

(d)

During the second quarter of 2010, ComEd recorded a reduction of $25 million to taxes other than income to reflect management’s estimate of future refunds for the 2008 and 2009 tax years associated with Illinois’ utility distribution tax based on an analysis of past refunds and interpretations of the Illinois Public Utility Act. Historically, ComEd has recorded refunds of the Illinois utility distribution tax when received. ComEd believes it now has sufficient, reliable evidence to record and support an estimated receivable associated with the anticipated refund for the 2008 and 2009 tax years.

(e)

Includes $70 million of under-recovered uncollectible accounts expense from 2008 and 2009 recorded in the first quarter of 2010 as well as $59 million of amortization of the associated regulatory asset. This amount also includes a credit of $3 million of under collections associated with 2010 activity. ComEd is recovering these costs through a rider mechanism authorized by the ICC. See Note 3—Regulatory Matters for additional information regarding the Illinois legislation for recovery of uncollectible accounts.

407

Combined Notes to Consolidated Financial Statements—(Continued)

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

(f)	Relates primarily to a decrease in interest payable associated with a change in uncertain income tax positions. See Note 12—Income Taxes for additional information.

(g)	Represents contingent liability recorded in connection with the December 9, 2010 acquisition of Exelon Wind. See Note 4—Acquisition for additional information.

DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2012, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $103 million, $56 million and $47 million, respectively, and reimbursements of $113 million, $66 million and $47 million, respectively, related to PECO’s and BGE’s DOE SGIG programs. For the year ended December 31, 2011, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $51 million, $51 million and $23 million, respectively, and reimbursements of $56 million, $56 million and $41 million, respectively, related to PECO’s and BGE’s DOE SGIG programs. See Note 3 - Regulatory Matters for additional information regarding the DOE SGIG.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2012 and 2011.


December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts ^(a)	$	22	$	—	$	6	$	8	$	8
Keystone Fuels, LLC		38		38		—		—		—
Conemaugh Fuels, LLC		26		26		—		—		—
CENG		1,849		1,849		—		—		—
Safe Harbor		293		293		—		—		—
Malacha		8		8		—		—		—
Other investments		34		33		—		—		—

Total equity method investments		2,270		2,247		6		8		8

Other investments:
Net investment in direct financing leases		685		—		—		—		—
Employee benefit trusts and investments ^(b)		100		22		8		22		5

Total investments	$	3,055	$	2,269	$	14	$	30	$	13

408

Combined Notes to Consolidated Financial Statements—(Continued)

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


December 31, 2011	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts ^(a)	$	15	$	—	$	6	$	8	$	8
Keystone Fuels, LLC		13		13		—		—		—
Conemaugh Fuels, LLC		16		16		—		—		—
Sacramento Solar		1		1		—		—		—

Total equity method investments		45		30		6		8		8

Other investments:
Net investment in direct financing leases		656		—		—		—		—
Employee benefit trusts and investments ^(b)		65		11		21		22		—

Total investments	$	766	$	41	$	27	$	30	$	8

(a)	Includes investments in financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in affiliates on the 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.

December 2010 IRS Payment (Exelon). In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions. In order to stop additional interest from accruing on the expected assessment resulting from the agreement, Exelon paid $302 million to the IRS on December 28, 2010. As of December 31, 2010, Exelon had not funded the specific bank account from which the IRS payment was disbursed resulting in a current liability. This amount was subsequently funded in January 2011. Under the authoritative guidance for offsetting balances, Exelon included this payment in Cash and cash equivalents with an offsetting amount in Other current liabilities on its Consolidated Balance Sheets. See Note 12—Income Taxes for additional information.

409

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. At December 31, 2012 and 2011, the components of the net investment in long-term leases were as follows:


	December 31,
	2012		2011
Estimated residual value of leased assets	$	1,492	$	1,492
Less: unearned income		807		836

Net investment in long-term leases	$	685	$	656

The following tables provide additional information about liabilities of the Registrants at December 31, 2012 and 2011.


December 31, 2012	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals ^(a)	$	708		$	371		$	125	$	45	$	38
Taxes accrued		353			247			61		3		22
Interest accrued		236			60			96		32		41
Severance accrued		91			42			4		1		5
Other accrued expenses		412	^(b)		396	^(b)		9		1		—

Total accrued expenses	$	1,800		$	1,116		$	295	$	82	$	106


December 31, 2011	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals ^(a)	$	520		$	264		$	127	$	48	$	42
Taxes accrued		297			241			59		5		26
Interest accrued		192			56			124		27		41
Severance accrued		15			9			2		1		—
Other accrued expenses		231	^(b)		209	^(b)		6		2		1

Total accrued expenses	$	1,255		$	779		$	318	$	83	$	110

(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

(b)	Includes $327 million and $184 million for amounts accrued related to Antelope Valley as of December 31, 2012 and December 31, 2011, respectively.

410

Combined Notes to Consolidated Financial Statements—(Continued)

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

Accumulated Other Comprehensive Income (Loss)

The following tables provide information about accumulated OCI income (loss) recorded (after tax) within Exelon’s Consolidated Balance Sheets at December 31, 2012 and 2011:


December 31, 2012	Exelon			Generation			ComEd			PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	367		$	513		$	—		$	—	$	—
Pension and non-pension postretirement benefit plans		(3,155	)		(19	)		—			—		—
Unrealized loss on marketable securities		21			19			—			1		—

Total accumulated other comprehensive income (loss)	$	(2,767	)	$	513		$	—		$	1	$	—


December 31, 2011	Exelon			Generation			ComEd			PECO		BGE
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges	$	488		$	915		$	—		$	—	$	—
Pension and non-pension postretirement benefit plans		(2,938	)		—			—			—		—
Unrealized loss on marketable securities		—			—			(1	)		—		—

Total accumulated other comprehensive income (loss)	$	(2,450	)	$	915		$	(1	)	$	—	$	—

21. Segment Information (Exelon, Generation, ComEd, PECO and BGE)

Exelon has nine reportable segments, ComEd, PECO, BGE and Generation’s six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. Generation’s expanded number of reportable segments is the result of the acquisition of Constellation on March 12, 2012. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon evaluates the performance of ComEd, PECO and BGE based on net income.

The foundation of Generation’s six reportable segments is based on the geographic location of its assets, and is largely representative of the footprints of an ISO / RTO and/or NERC region. Descriptions of each of Generation’s six reportable segments are as follows:

•

New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•

New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•

ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

411

Combined Notes to Consolidated Financial Statements—(Continued)

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

•

Other Regions not considered individually significant:

•

Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO.

Exelon and Generation evaluate the performance of Generation’s power marketing activities based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of 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. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for our own generation and fuel costs associated with tolling agreements. Generation’s other business activities, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency and demand response, the design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, are not allocated to regions. Further, Generation’s compensation under the reliability-must-run rate schedule, results of operations from the Brandon Shores, Wagner, and C.P. Crane Maryland generating stations, and other miscellaneous revenues, mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger are also not allocated to a region.

412

Combined Notes to Consolidated Financial Statements—(Continued)

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

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2012, 2011 and 2010 is as follows:


	Generation ^(a)			ComEd		PECO		BGE^(b)			Other^(c)			Intersegment Eliminations			Exelon
Operating revenues ^(d):
2012	$	14,437		$	5,443	$	3,186	$	2,091		$	1,396		$	(3,064	)	$	23,489
2011		10,447			6,056		3,720		—			830			(1,990	)		19,063
2010		10,025			6,204		5,519		—			755			(3,859	)		18,644
Intersegment revenues ^(e):
2012	$	1,702		$	2	$	3	$	9		$	1,381		$	(3,042	)	$	55
2011		1,161			2		5		—			831			(1,990	)		9
2010		3,102			2		5		—			756			(3,859	)		6
Depreciation and amortization
2012	$	768		$	610	$	217	$	238		$	46		$	2		$	1,881
2011		570			554		202		—			21			—			1,347
2010		474			516		1,060		—			25			—			2,075
Operating expenses ^(d):
2012	$	13,226		$	4,557	$	2,563	$	2,053		$	1,662		$	(3,043	)	$	21,018
2011		7,571			5,074		3,065		—			863			(1,990	)		14,583
2010		6,979			5,148		4,858		—			792			(3,859	)		13,918
Equity in earnings (losses) of unconsolidated affiliates
2012	$	(91	)	$	—	$	—	$	—		$	—		$	—		$	(91	)
2011		(1	)		—		—		—			—			—			(1	)
2010		—			—		—		—			—			—			—
Interest expense, net:
2012	$	301		$	307	$	123	$	111		$	86		$	—		$	928
2011		170			345		134		—			77			—			726
2010		153			386		193		—			85			—			817
Income (loss) before income taxes:
2012	$	1,058		$	618	$	508	$	(54	)	$	(276	)	$	(56	)	$	1,798
2011		2,827			666		535		—			(59	)		(13	)		3,956
2010		3,150			694		476		—			(91	)		(8	)		4,221
Income taxes:
2012	$	500		$	239	$	127	$	(23	)	$	(215	)	$	(1	)	$	627
2011		1,056			250		146		—			9			(4	)		1,457
2010		1,178			357		152		—			(27	)		(2	)		1,658
Net income (loss):
2012	$	558		$	379	$	381	$	(31	)	$	(61	)	$	(55	)	$	1,171
2011		1,771			416		389		—			(68	)		(9	)		2,499
2010		1,972			337		324		—			(64	)		(6	)		2,563
Capital expenditures:
2012	$	3,554		$	1,246	$	422	$	500		$	67		$	—		$	5,789
2011		2,491			1,028		481		—			42			—			4,042
2010		1,883			962		545		—			14			(78	)^(f)		3,326
Total assets:
2012	$	40,681		$	22,905	$	9,353	$	7,499		$	10,432		$	(12,316	)	$	78,554
2011		27,433			22,638		9,156		—			6,147			(10,379	)		54,995

413

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)

Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the year ended December 31, 2012 include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the years ended December 31, 2011 and 2010 intersegment revenues for Generation include revenue from sales to PECO of $508 million and $2,092 million, respectively, in the Mid-Atlantic region, and sales to ComEd of $653 million and $1,010 million, respectively, in the Midwest region.

(b)	Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2012.

(c)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.

(d)

For the years ended December 31, 2012, 2011 and 2010, utility taxes of $82 million, $27 million and $0 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2012, 2011 and 2010, utility taxes of $239 million, $243 million and $205 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2012, 2011 and 2010, utility taxes of $141 million, $173 million and $271 million, respectively, are included in revenues and expenses for PECO. For the period of March 12, 2012 through December 31, 2012, utility taxes of $59 million are included in revenues and expenses for BGE.

(e)

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 3 for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.

(f)	Represents capital projects transferred from BSC to Generation, ComEd and PECO. These projects are shown as capital expenditures at Generation, ComEd and PECO and the capital expenditure is eliminated upon consolidation.

Generation total revenues:


	2012							2011						2010
	Revenues from external customers ^(a)		Interseg ment revenues			Total Revenues		Revenues from external customers ^(a)		Interseg ment revenues		Total Revenues		Revenues from external customers ^(a)		Interseg ment revenues		Total Revenues
Mid-Atlantic	$	5,082	$	(44	)	$	5,038	$	4,052	$	—	$	4,052	$	3,232	$	—	$	3,232
Midwest		4,824		24			4,848		5,445		—		5,445		5,762		—		5,762
New England		1,048		45			1,093		11		—		11		14		—		14
New York		582		(25	)		557		—		—		—		—		—		—
ERCOT		1,365		2			1,367		575		—		575		543		—		543
Other Regions ^(b)		755		78			833		201		—		201		149		—		149

Total Revenues for Reportable Segments	$	13,656	$	80		$	13,736	$	10,284	$	—	$	10,284	$	9,700	$	—	$	9,700

Other ^(c)		781		(80	)		701		163		—		163		325		—		325

Total Generation Consolidated Operating Revenues	$	14,437	$	—		$	14,437	$	10,447	$	—	$	10,447	$	10,025	$	—	$	10,025

(a)	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.

(b)	Other regions include the South, West and Canada, which are not considered individually significant.

(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the merger date.

414

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation total revenues net of purchased power and fuel expense:


	2012							2011								2010
	RNF from external customers ^(a)		Interseg ment RNF			Total RNF		RNF from external customers ^(a)			Interseg ment RNF		Total RNF			RNF from external customers ^(a)			Interseg ment RNF		Total RNF
Mid-Atlantic	$	3,477	$	(44	)	$	3,433	$	3,350		$	—	$	3,350		$	2,501		$	—	$	2,501
Midwest		2,974		24			2,998		3,547			—		3,547			4,081			—		4,081
New England		151		45			196		9			—		9			11			—		11
New York		101		(25	)		76		—			—		—			—			—		—
ERCOT		403		2			405		84			—		84			(66	)		—		(66	)
Other Regions ^(b)		53		78			131		(14	)		—		(14	)		(65	)		—		(65	)

Total Revenues net of purchased power and fuel expense for Reportable Segments	$	7,159	$	80		$	7,239	$	6,976		$	—	$	6,976		$	6,462		$	—	$	6,462

Other ^(c)		217		(80	)		137		(118	)		—		(118	)		100			—		100

Total Generation Revenues net of purchased power and fuel expense	$	7,376	$	—		$	7,376	$	6,858		$	—	$	6,858		$	6,562		$	—	$	6,562

(a)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b)	Other regions includes the South, West and Canada, which are not considered individually significant.

(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the merger date.

415

Combined Notes to Consolidated Financial Statements—(Continued)

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

22. Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE)

Exelon

The financial statements of Exelon include related party transactions as presented in the tables below:


	For the Years Ended December 31,
	2012			2011			2010
Operating revenues from affiliates:
PECO ^(a)	$	6		$	9		$	6
CENG ^(b)		42			—			—

Total operating revenues from affiliates	$	48		$	9		$	6

Fuel and purchased power from related parties:
CENG ^(c)	$	793		$	—		$	—
Keystone Fuels, LLC		61			68			74
Conemaugh Fuels, LLC		68			69			70

Total fuel purchases from related parties	$	922		$	137		$	144

Charitable contribution to Exelon Foundation ^(d)	$	7		$	—		$	10
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	13		$	13
PECO Trust III		6			6			6
PECO Trust IV		6			6			6

Total interest expense to affiliates, net	$	25		$	25		$	25

(Loss) gain in equity method investments:
CENG equity investment income	$	73		$	—			—
Amortization of basis difference in CENG ^(e)		(172	)		—			—
Other		8			(1	)		—

Total loss in equity method investments	$	(91	)	$	(1	)	$	—


				December 31,
				2012			2011
Investments in affiliates:
ComEd Financing III				$	6		$	6
PECO Energy Capital Corporation					4			4
PECO Trust IV					4			5
BGE Capital Trust II					8			—

Total investments in affiliates				$	22		$	15

Receivables from affiliates (current):
CENG ^(b)				$	16		$	—
Payables to affiliates (current):
CENG ^(c)				$	83		$	—
ComEd Financing III					4			4
PECO Trust III					1			1

Total payables to affiliates (current)				$	88		$	5

Long-term debt to BondCo and other financing trusts (including due within one year):
ComEd Financing III				$	206		$	206
PECO Trust III					81			81
PECO Trust IV					103			103
BGE Capital Trust II					258			—

Total long-term debt due to financing trusts				$	648		$	390

416

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)	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 3—Regulatory Matters for additional information.

(b)

Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Under the SSA, BSC provides a variety of support services to CENG. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services.

(c)

A subsidiary of Generation has an agreement under which it is purchasing 85-90% of the output of CENG’s nuclear plants that is not sold to third parties under pre-existing firm and unit contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit contingent basis 50.01% of the output of CENG’s nuclear plants, and EDF will purchase on a unit contingent basis 49.99% of the output.

(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)

As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities impact the earnings of CENG. In future periods, Generation may be eligible for distributions from CENG in excess of its 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. Through purchase accounting, Generation recorded the fair value of expected future distributions. Generation will record these distributions when realized as a reduction in its investment in CENG. Distributions realized in excess of the fair value recorded would be recorded in earnings in the period earned.

417

Combined Notes to Consolidated Financial Statements—(Continued)

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

Transactions involving Generation, ComEd, PECO and BGE 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,
	2012			2011			2010
Operating revenues from affiliates:
ComEd ^(a)	$	795		$	653		$	1,010
PECO ^(b)		543			508			2,092
BGE ^(c)		322			—			—
CENG ^(d)		42			—			—

Total operating revenues from affiliates	$	1,702		$	1,161		$	3,102

Fuel and purchased power from related parties:
PECO	$	—		$	1		$	1
BGE		8			—			—
CENG ^(e)		793			—			—
Keystone Fuels, LLC		61			68			74
Conemaugh Fuels, LLC		68			69			70

Total fuel purchases from related parties	$	930		$	138		$	145

Operating and maintenance from affiliates:
ComEd ^(f)	$	2		$	2		$	2
PECO ^(f)		3			5			4
BSC ^(g)		625			314			285

Total operating and maintenance from affiliates	$	630		$	321		$	291

(Loss) gain in equity method investments
CENG equity investment income		73			—			—
Amortization of basis difference in CENG ^(h)		(172	)		—			—
Qualifying facilities and domestic power projects		8			(1	)		—

Total loss in equity method investments		(91	)	$	(1	)	$	—

Cash distribution paid to member	$	1,626		$	172		$	1,508
Contribution from member	$	48		$	30		$	62

418

Combined Notes to Consolidated Financial Statements—(Continued)

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


	December 31,
	2012		2011
Mark-to-market derivative assets with affiliates (current):
ComEd ⁽ⁱ⁾	$	226	$	503
Receivables from affiliates (current):
ComEd ^(a)(j)	$	54	$	70
PECO ^(b)		56		39
BGE ^(c)		31		—

Total receivables from affiliates (current)	$	141	$	109

Receivable from affiliate (noncurrent)
Exelon	$	1	$	1
Mark-to-market derivative assets with affiliates (noncurrent):
ComEd ⁽ⁱ⁾	$	—	$	191
Payables to affiliates (current):
CENG ^(e)	$	83	$	—
Exelon ^(k)		33		7
BSC ^(g)		77		51

Total payables to affiliates (current)	$	193	$	58

Payables to affiliates (noncurrent):
ComEd ^(l)	$	2,037	$	1,857
PECO ^(l)		360		365

Total payables to affiliates (noncurrent)	$	2,397	$	2,222

(a)

Generation has 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 3—Regulatory Matters for additional information.

(b)	Generation had a PPA with PECO to provide the full energy requirements to PECO through 2010. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.

(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(d)

(e)

(f)	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.

(g)	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.

419

Combined Notes to Consolidated Financial Statements—(Continued)

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

(h)

(i)	Represents the fair value of Generation’s five-year financial swap contract with ComEd.

(j)

Generation had a $53 million and $53 million receivable from ComEd at December 31, 2012 and 2011, respectively, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3—Regulatory Matters and Note 10—Derivative Financial Instruments for additional information.

(k)	In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

(l)

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 13—Asset Retirement Obligations.

ComEd

The financial statements of ComEd include related party transactions as presented in the tables below:


	For the Years Ended December 31,
	2012		2011		2010
Operating revenues from affiliates
Generation	$	2	$	2	$	2
Purchased power from affiliate
Generation ^(a)	$	789	$	653	$	1,010
Operating and maintenance from affiliate
BSC ^(b)	$	163	$	158	$	152
Interest expense to affiliates, net:
Exelon	$	—	$	2	$	—
ComEd Financing III		13		13		13

Total interest expense to affiliates, net	$	13	$	15	$	13

Capitalized costs
BSC ^(b)	$	92	$	85	$	84
Cash dividends paid to parent	$	105	$	300	$	310
Contribution from parent	$	11	$	11	$	2

420

Combined Notes to Consolidated Financial Statements—(Continued)

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


	December 31,
	2012		2011
Prepaid voluntary employee beneficiary association trust ^(c)	$	10	$	12
Investment in affiliate
ComEd Financing III	$	6	$	6
Receivable from affiliates (noncurrent):
Generation ^(d)	$	2,037	$	1,857
Other		2		3

Total receivable from affiliates (noncurrent)	$	2,039	$	1,860

Payables to affiliates (current):
Generation ^(a)(e)	$	54	$	70
BSC ^(b)		35		35
ComEd Financing III		4		4
Other		4		2

Total payables to affiliates (current)	$	97	$	111

Mark-to-market derivative liability with affiliate (current)
Generation ^(f)	$	226	$	503
Mark-to-market derivative liability with affiliate (noncurrent)
Generation ^(f)	$	—	$	191
Long-term debt to ComEd financing trust
ComEd Financing III	$	206	$	206

(a)

ComEd procures a portion of its electricity supply requirements from Generation under 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 Legislation. See Note 3—Regulatory Matters and Note 10—Derivative Financial Instruments for additional information.

(b)	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.

(c)

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.

(d)

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.

(e)

ComEd had a $53 million and $53 million payable to Generation at December 31, 2012 and 2011, respectively, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement Legislation. See Note 3—Regulatory Matters and Note 10—Derivative Financial Information for additional information.

(f)	To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap with Generation.

421

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,
	2012		2011		2010
Operating revenues from affiliates:
Generation ^(a)	$	3	$	5	$	5
Purchased power from affiliate
Generation ^(b)	$	533	$	495	$	2,085
Operating and maintenance from affiliates:
BSC ^(c)	$	107	$	92	$	89
Generation		4		4		—

Total operating and maintenance from affiliates	$	111	$	96	$	89

Interest expense to affiliates, net:
PECO Trust III	$	6	$	6	$	6
PECO Trust IV		6		6		6

Total interest expense to affiliates, net	$	12	$	12	$	12

Capitalized costs
BSC ^(c)	$	54	$	60	$	40
Cash dividends paid to parent	$	343	$	348	$	224
Repayment of receivable from parent	$	—	$	—	$	180
Contribution from parent	$	9	$	18	$	43


	December 31,
	2012		2011
Prepaid voluntary employee beneficiary association trust ^(d)	$	2	$	3
Investments in affiliates:
PECO Energy Capital Corporation	$	4	$	4
PECO Trust IV		4		4

Total investments in affiliates	$	8	$	8

Receivable from affiliate (noncurrent):
Generation ^(e)	$	360	$	365
Payables to affiliates (current):
Generation ^(b)	$	56	$	39
BSC ^(c)		18		21
Exelon		1		1
PECO Trust III		1		1

Total payables to affiliates (current)	$	76	$	62

Long-term debt to financing trusts (including amounts due within one year):
PECO Trust III	$	81	$	81
PECO Trust IV		103		103

Total long-term debt to financing trusts	$	184	$	184

(a)	PECO provides energy to Generation for Generation’s own use.

422

Combined Notes to Consolidated Financial Statements—(Continued)

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

(b)

PECO obtained all of its electric supply from Generation through 2010 under a PPA. Beginning January 1, 2011, PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.

(c)	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.

(d)

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.

(e)

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.

BGE

The financial statements of BGE include related party transactions as presented in the tables below:


	For the Years Ended December 31,
	2012		2011			2010
Operating revenues from affiliates:
Generation ^(a)	$	10	$	8		$	7
Purchased power from affiliate
Generation ^(b)	$	396	$	348		$	428
Operating and maintenance from affiliates:
BSC ^(c)	$	106	$	150		$	126
Capitalized costs
BSC ^(c)	$	21	$	29		$	49
Cash dividends paid to parent	$	—	$	(85	)	$	—
Contribution from parent	$	66	$	—		$	—


	December 31,
	2012		2011
Investments in affiliates:
BGE Capital Trust II	$	8	$	8
Payables to affiliates (current):
Generation ^(b)	$	31	$	41
BSC ^(c)		12		—
Exelon ^(d)		17		—
ComEd		3		—
PECO		2		—

Total payables to affiliates (current)	$	65	$	41

Long-term debt to BGE financing trust
BGE Capital Trust II	$	258	$	258

(a)	BGE provides energy to Generation for Generation’s own use.

(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

423

Combined Notes to Consolidated Financial Statements—(Continued)

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

(c)	BGE 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)	BGE receives a variety of corporate support services from Exelon Corporate, including payroll and benefits services.

23. Quarterly Data (Unaudited) (Exelon, Generation, ComEd and PECO)

Exelon

The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:


	Operating Revenues				Operating Income				Net Income on Common Stock
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	4,686	$	4,956	$	359	$	1,202	$	200	$	668
June 30		5,954		4,496		714		1,034		286		620
September 30		6,565		5,254		603		1,181		296		601
December 31		6,284		4,357		704		1,062		378		606


	Average Basic Shares Outstanding (in millions)				Net Income per Basic Share
	2012		2011		2012		2011
Quarter ended:
March 31		705		662	$	0.28	$	1.01
June 30		853		663		0.34		0.93
September 30		854		663		0.35		0.91
December 31		854		664		0.44		0.91

	Average Diluted Shares Outstanding (in millions)				Net Income per Diluted Share
	2012		2011		2012		2011
Quarter ended:
March 31		707		664	$	0.28	$	1.01
June 30		856		664		0.33		0.93
September 30		857		665		0.35		0.90
December 31		857		666		0.44		0.91

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


	2012								2011
	Fourth		Third		Second		First		Fourth			Third		Second		First
	Quarter		Quarter		Quarter		Quarter		Quarter			Quarter		Quarter		Quarter
High price	$	37.50	$	39.82	$	39.37	$	43.70	$	45.45		$	45.27	$	42.89	$	43.58
Low price		28.40		34.54		36.27		38.31		39.93			39.51		39.53		39.06
Close		29.74		35.58		37.62		39.21		43.37			42.61		42.84		41.24
Dividends		0.525		0.525		0.525		0.525		0.525	^(a)		0.525		0.525		0.525

424

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)

The fourth quarter 2011 dividend does not include the first quarter 2012 regular quarterly dividend of $0.525 per share, declared by the Exelon Board of Directors on October 25, 2011. The first quarter 2012 dividend is payable on March 9, 2012, to shareholders of record of Exelon at the end of the day on February 15, 2012.

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 on Membership Interest
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	2,739	$	2,643	$	272	$	801	$	168	$	495
June 30		3,753		2,455		384		647		166		443
September 30		4,017		2,821		174		754		91		386
December 31		3,928		2,528		290		673		137		447

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
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	1,388	$	1,466	$	226	$	200	$	87	$	69
June 30		1,281		1,444		142		254		42		114
September 30		1,484		1,784		218		243		90		112
December 31		1,290		1,362		300		285		160		121

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
	2012		2011		2012		2011		2012		2011
Quarter ended:
March 31	$	875	$	1,153	$	177	$	210	$	96	$	125
June 30		715		842		151		161		79		82
September 30		806		946		178		153		122		104
December 31		790		778		117		131		79		73

425

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:


	Operating Revenues				Operating (Loss) Income					Net (Loss) Income on Common Stock
	2012		2011		2012			2011		2012			2011
Quarter ended:
March 31	$	696	$	976	$	(11	)	$	153	$	(33	)	$	78
June 30		616		674		52			54		13			13
September 30		720		745		30			23		(4	)		(2	)
December 31		703		673		61			84		15			34

426

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Exelon, Generation, ComEd, PECO and BGE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Exelon, Generation, ComEd, PECO and BGE—Disclosure Controls and Procedures

During the fourth quarter of 2012, each registrant’s management, including its principal executive officer and principal financial officer, evaluated the effectiveness of 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, 2012, 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.

Exelon, Generation, ComEd, PECO and BGE—Changes in Internal Control Over Financial Reporting

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 2012 that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s internal control over financial reporting.

Exelon, Generation, ComEd, PECO and BGE—Internal Control Over Financial Reporting

Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2012. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2012 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.

427

ITEM 9B.

OTHER INFORMATION

Exelon, Generation and ComEd

Anne R. Pramaggiore, President and Chief Operating Officer of ComEd, Michael J. Pacilio, President, Exelon Nuclear and Chief Nuclear Officer, Generation, and Sunil Garg, President, Exelon Power and Senior Vice President, Generation, each entered into a Change in Control Employment Agreement effective as of February 10, 2011. The terms of these change in control employment agreements are substantially the same as the change in control employment agreements entered into by other senior executives and previously disclosed, except that the agreements with Ms. Pramaggiore and Messrs. Pacilio and Garg do not include excise tax gross-up provisions, consistent with a policy adopted by the compensation committee in April 2009. The form of Change in Control Employment Agreement is attached hereto as Exhibit 10-44.

PECO and BGE

None.

428

PART III

Exelon Generation Company, LLC and Baltimore Gas and Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to Generation and BGE are not presented.

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 21, 2013.

Directors, Director Nomination Process, and Audit Committee

The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)) and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in Exelon’s definitive 2013 proxy statement (2013 Exelon Proxy Statement) and the ComEd and PECO information statements to be filed with the SEC before April 30, 2013 pursuant to Regulation 14A or 14C, as applicable, 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, ComEd’s, and PECO’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website 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.

429

ITEM 11.

EXECUTIVE COMPENSATION

The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the 2013 Exelon Proxy Statement or the ComEd and PECO 2013 information statements and incorporated herein by reference.

430

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The additional information required by this item will be set forth under Ownership of Exelon Stock in the 2013 Exelon Proxy Statement or the ComEd and PECO 2013 information statements and incorporated herein by reference.

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 2)

Equity compensation plans approved by security holders

13,449,422

48.47

24,302,890

(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, Executive Compensation—Non-employee Director Compensation. See Note 17 of the Combined Notes to Consolidated Financial Statements for additional information.

(2)	Excludes securities to be issued upon exercise of outstanding options and vesting of shares or deferred stock units shown in column [B].

No ComEd or PECO securities are authorized for issuance under equity compensation plans.

431

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the 2013 Exelon Proxy Statement or the ComEd and PECO 2013 information statements and incorporated herein by reference.

432

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent Accountant for 2013 in the Proxy Statement and incorporated herein by reference.

433

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

The following documents are filed as a part of this report:

Exelon


1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 21, 2013 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Balance Sheets at December 31, 2012 and 2011

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2012 and 2011 and for the Years Ended December 31, 2012, 2011 and 2010

		Schedule II—Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.

434

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Operations and Other Comprehensive Income


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Operating expenses
Operating and maintenance	$	201		$	56		$	13
Operating and maintenance from affiliates		72			44			22
Other		6			4			2

Total operating expenses		279			104			37
Operating loss		(279	)		(104	)		(37	)

Other income and (deductions)
Interest expense, net		(153	)		(75	)		(90	)
Equity in earnings of investments		1,278			2,662			2,652
Interest income from affiliates, net		75			1			—
Other, net		7			8			6

Total other income and (deductions)		1,207			2,596			2,568

Income before income taxes		928			2,492			2,531
Income taxes		(232	)		(3	)		(32	)

Net income	$	1,160		$	2,495		$	2,563

Other comprehensive loss
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs, net of taxes of $1, $(4) and $(7), respectively		1			(5	)		(11	)
Actuarial loss reclassified to periodic cost, net of taxes of $110, $93 and $79, respectively		170			136			114
Transition obligation reclassified to periodic cost, net of taxes of $2, $2 and $2, respectively		2			4			3
Pension and non-pension postretirement benefit plan valuation adjustment, net of taxes of $(237), $(171) and $(188), respectively		(372	)		(250	)		(288	)
Change in unrealized gain (loss) on cash flow hedges, net of taxes of $(67), $39 and $(107), respectively		(121	)		88			(151	)
Change in unrealized gain (loss) on marketable securities, net of taxes of $(1), $0 and $0, respectively		1			—			—
Change in unrealized gain (loss) on equity investments, net of taxes of $(1), $0 and $0, respectively		2			—			—
Change in unrealized gain (loss) on foreign currency translation, net of taxes of $0, $0 and $0, respectively		—			—			(1	)

Other comprehensive loss		(317	)		(27	)		(334	)

Comprehensive income	$	843		$	2,468		$	2,229

See Notes to Financial Statements

435

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2012			2011			2010
Net cash flows provided by operating activities	$	2,131		$	766		$	2,014

Cash flows from investing activities
Capital expenditures		(30	)		(28	)		(7	)
Return on capital from equity method investee		—			(1	)		92
Cash and restricted cash acquired from Constellation		679			—			—
Change in restricted cash		(38	)		—			—
Investment in unconsolidated affiliates		(67	)		(65	)		(290	)

Net cash flows used in investing activities		544			(94	)		(205	)

Cash flows from financing activities
Changes in Exelon intercompany money pool		(703	)		20			(5	)
Changes in short-term debt		(161	)		161			—
Retirement of long-term debt		(77	)		—			(400	)
Dividends paid on common stock		(1,716	)		(1,393	)		(1,389	)
Proceeds from employee stock plans		73			38			48
Other financing activities		30			(1	)		5

Net cash flows used in financing activities		(2,554	)		(1,175	)		(1,741	)

Increase (decrease) in cash and cash equivalents		121			(503	)		68
Cash and cash equivalents at beginning of period		38			541			473

Cash and cash equivalents at end of period	$	159		$	38		$	541

See Notes to Financial Statements

436

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets


	December 31,
(In millions)	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	159	$	38
Restricted cash and investments		38		—
Accounts receivable, net
Other accounts receivable		25		111
Accounts receivable from affiliates		87		9
Deferred income taxes		—		22
Notes receivable from affiliates		119		—
Regulatory assets		381		—
Other		2		3

Total current assets		811		183

Property, plant and equipment, net		59		32
Deferred debits and other assets
Regulatory assets		3,932		2,991
Investments in affiliates		25,576		18,951
Deferred income taxes		2,437		2,058
Notes receivable from affiliates		2,007		—
Other		42		24

Total deferred debits and other assets		33,994		24,024

Total assets	$	34,864	$	24,239

See Notes to Financial Statements

437

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets


	December 31,
(In millions)	2012			2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—		$	161
Accounts payable		101			—
Payables to affiliates		—			30
Unamortized energy contract liabilities		77			—
Accrued expenses		110			117
Deferred income taxes		55			—
Other		60			403

Total current liabilities		403			711

Long-term debt		3,576			1,313
Deferred credits and other liabilities
Pension obligations		8,252			6,797
Non-pension postretirement benefit obligations		1,071			965
Unamortized energy contract liabilities		12			—
Other		116			68

Total deferred credits and other liabilities		9,451			7,830

Total liabilities		13,430			9,854

Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 890 and 662 shares outstanding at December 31, 2012 and 2011, respectively)		16,632			9,107
Treasury stock, at cost (35 shares held at December 31, 2012 and 2011, respectively)		(2,327	)		(2,327	)
Retained earnings		9,893			10,055
Accumulated other comprehensive loss, net		(2,767	)		(2,450	)

Total shareholders’ equity		21,431			14,385

BGE preference stock not subject to mandatory redemption		3			—

Total liabilities and shareholders’ equity	$	34,864		$	24,239

See Notes to Financial Statements

438

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

1. Basis of Presentation

Exelon Corporate is a holding company that 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 of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, PECO Energy Company (PECO), of which Exelon Corporate owns 100% of the common stock but none of PECO’s preferred securities and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock.

2. Merger with Constellation

On March 12, 2012, Exelon Corporation completed the merger contemplated by the Merger Agreement, among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’s interest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon’s interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including the customer supply and generation businesses that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger.

For BGE’s debt, fuel supply contracts and regulatory assets not earning a return, the difference between fair value and book value of BGE’s assets acquired and liabilities assumed is recorded as a regulatory asset at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 4—Merger and Acquisitions of the Combined Notes to Consolidated Financial Statements for additional information on the merger with Constellation. Also see Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information on BGE’s push-down accounting treatment.

3. 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 no commercial paper borrowings at December 31, 2012 and $161 million at December 31, 2011.

Credit Agreements

On August 10, 2012, Exelon Corporate amended and extended its unsecured syndicated revolving credit facility with aggregate bank commitments of $500 million through August 10, 2017. As of

439

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

December 31, 2012, Exelon Corporate had available capacity under those commitments of $498 million. See Note 11—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon Corporate’s credit agreement.

Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2012 and 2011:


	Rates		Maturity Date		December 31,
	Rates		Maturity Date		2012		2011
Long-term debt
Senior unsecured notes		4.55% – 8.63%		2015-2063	$	3,108	$	1,300
Unamortized debt discount and premium, net						2		(1	)
Fair value adjustment						455		—
Fair value hedge carrying value adjustment, net						11		14

Long-term debt					$	3,576	$	1,313

Exelon Corporate will not have any long-term debt maturities in periods 2013 and 2014. The debt maturities for the periods 2015, 2016, 2017 and thereafter are as follows:


2015	$	1,350
2016		—
2017		—
Remaining years		1,758

Total long-term debt	$	3,108

4. Commitments and Contingencies

See Note 19 of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters, savings plan claim and fund transfer restrictions.

440

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

5. 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,
	2012			2011			2010
Operating and maintenance from affiliates:
Business Services Company, LLC ^(a)	$	72		$	44		$	22
Interest income from affiliates, net	$	75		$	1		$	—
Equity in earnings of investments:
Exelon Energy Delivery Company, LLC ^(b)	$	713		$	801		$	657
Exelon Ventures Company, LLC ^(c)		564			1,769			1,978
UII, LLC		25			18			23
Exelon Transmission Company, LLC		(3	)		(3	)		(6	)
Exelon Consolidations ^(d)		(21	)		77			—

Total equity in earnings of investments	$	1,278		$	2,662		$	2,652

Charitable contributions to Exelon Foundation ^(e)	$	—		$	—		$	10
Cash contributions received from affiliates	$	2,074		$	820		$	2,056


	December 31,
	2012		2011
Accounts receivable from affiliates (current):
Business Services Company, LLC ^(a)	$	33	$	—
Generation		33		7
ComEd		2		1
PECO		2		1
BGE		17		—

Total accounts receivable from affiliates (current)	$	87	$	9

Notes receivable from affiliates (current):
Business Services Company, LLC ^(a)	$	119	$	—

Investments in affiliates:
Business Services Company, LLC ^(a)	$	181	$	160
Exelon Energy Delivery Company, LLC ^(b)		12,466		10,040
Exelon Ventures Company, LLC ^(c)		12,444		8,310
UII, LLC		472		447
Exelon Transmission Company, LLC		4		6
VEBA		9		(12	)

Total investments in affiliates	$	25,576	$	18,951

Notes receivable from affiliates (non-current):
Generation	$	2,007	$	—

Payables to affiliates (current)
Exelon Consolidations	$	—	$	27
Business Services Company, LLC ^(a)		—		3

Total payables to affiliates (current)	$	—	$	30

441

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

(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 Energy Delivery Company, LLC consists of ComEd, PECO and BGE.

(c)	Exelon Ventures Company, LLC primarily consists of Generation.

(d)	Equity in earnings of investments for Exelon Consolidations represents the intercompany income component that offsets the corresponding intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(e)

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).

442

Exelon Corporation and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
*For The Year Ended December 31, 2012*

Allowance for uncollectible accounts ^(a)	$	199	$	144		$	136	^(b)(c)	$	186	^(d)	$	293

Deferred tax valuation allowance		10		18			18	^(b)		10			36

Reserve for obsolete materials		60		2			2	^(b)		11			53

*For The Year Ended December 31, 2011*

Allowance for uncollectible accounts ^(a)	$	211	$	121		$	32	^(c)	$	165	^(d)	$	199

Deferred tax valuation allowance		9		1			—			—			10

Reserve for obsolete materials		56		6			—			2			60

*For The Year Ended December 31, 2010*

Allowance for uncollectible accounts ^(a)	$	214	$	109		$	19	^(c)	$	131	^(d)	$	211

Deferred tax valuation allowance		36		(8	)		—			19			9

Reserve for obsolete materials		45		12			—			1			56

(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, $17 million and $11 million for the years ended December 31, 2012, 2011, 2010 and 2009, respectively.

(b)	Primarily represents the addition of Constellation’s and BGE’s results as of March 12, 2012, the date of the merger.

(c)	Includes charges for late payments and non-service receivables.

(d)	Write-off of individual accounts receivable.

443

Exelon Generation Company, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Generation



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 21, 2013 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Balance Sheets at December 31, 2012 and 2011

		Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 2012, 2011 and 2010

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

444

Exelon Generation Company, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D		Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions		Balance at End of Period
	(in millions)
*For The Year Ended December 31, 2012*

Allowance for uncollectible accounts	$	29	$	—	$	66	^(a)	$	11	$	84

Deferred tax valuation allowance		—		17		18	^(a)		—		35

Reserve for obsolete materials		59		—		2	^(a)		11		50

*For The Year Ended December 31, 2011*

Allowance for uncollectible accounts	$	32	$	—	$	—		$	3	$	29

Deferred tax valuation allowance		—		—		—			—		—

Reserve for obsolete materials		55		4		—			—		59

*For The Year Ended December 31, 2010*

Allowance for uncollectible accounts	$	31	$	1	$	—		$	—	$	32

Deferred tax valuation allowance		18		—		—			18		—

Reserve for obsolete materials		43		12		—			—		55

(a)	Represents the addition of Constellation’s results as of March 12, 2012, the date of the merger.

445

Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

ComEd



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 21, 2013 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Balance Sheets at December 31, 2012 and 2011

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

446

Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)

*For The Year Ended December 31, 2012*

Allowance for uncollectible accounts	$	78	$	42	$	26	^(a)	$	76	^(b)	$	70

Reserve for obsolete materials		1		1		—			—			2

*For The Year Ended December 31, 2011*

Allowance for uncollectible accounts	$	80	$	57	$	15	^(a)	$	74	^(b)	$	78

Reserve for obsolete materials		1		2		—			2			1

*For The Year Ended December 31, 2010*

Allowance for uncollectible accounts	$	77	$	48	$	16	^(a)	$	61	^(b)	$	80

Reserve for obsolete materials		1		—		—			—			1

(a)	Primarily charges for late payments and non-service receivables.

(b)	Write-off of individual accounts receivable.

447

PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

PECO



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 21, 2013 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Balance Sheets at December 31, 2012 and 2011

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

448

PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)

*For The Year Ended December 31, 2012*

Allowance for uncollectible accounts ^(a)	$	92	$	60	$	8	^(b)	$	61	^(c)	$	99

Deferred tax valuation allowance		—		—		—			—			—

Reserve for obsolete materials		1		—		—			—			1

*For The Year Ended December 31, 2011*

Allowance for uncollectible accounts ^(a)	$	99	$	64	$	17	^(b)	$	88	^(c)	$	92

Deferred tax valuation allowance		—		—		—			—			—

Reserve for obsolete materials		1		—		—			—			1

*For The Year Ended December 31, 2010*

Allowance for uncollectible accounts ^(a)	$	106	$	60	$	3	^(b)	$	70	^(c)	$	99

Deferred tax valuation allowance		1		—		—			1			—

Reserve for obsolete materials		1		—		—			—			1

(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, $17 million and $11 million for the years ended December 31, 2012, 2011, 2010 and 2009, respectively.

(b)	Primarily charges for late payments.

(c)	Write-off of individual accounts receivable.

449

Baltimore Gas and Electric Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

BGE



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 21, 2013 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

		Consolidated Balance Sheets at December 31, 2012 and 2011

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

450

Baltimore Gas and Electric Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C				Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions			Balance at End of Period
	(in millions)

*For The Year Ended December 31, 2012*

Allowance for uncollectible accounts	$	38	$	45	$	—	$	43	^(a)	$	40

Deferred tax valuation allowance		—		1		—		—			1

Reserve for obsolete materials		—		1		—		—			1

*For The Year Ended December 31, 2011*

Allowance for uncollectible accounts	$	36	$	39	$	—	$	37	^(a)	$	38

Deferred tax valuation allowance		—		—		—		—			—

Reserve for obsolete materials		—		—		—		—			—

*For The Year Ended December 31, 2010*

Allowance for uncollectible accounts	$	47	$	46	$	—	$	57	^(a)	$	36

Deferred tax valuation allowance		—		—		—		—			—

Reserve for obsolete materials		—		—		—		—			—

(a)	Write-off of individual accounts receivable.

451

(b) Exhibits required by Item 601 of Regulation S-K:

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, Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1).

2-2		Purchase Agreement dated as of August 30, 2010 by and between Deere & Company and Generation (File No. 1-16169, Form 10-Q for the quarter ended September 30, 2010, Exhibit 2-1).

2-3		Agreement and Plan of Merger dated as of April 28, 2011 by and among Exelon Corporation, Bolt Acquisition Corporation and Constellation Energy Group, Inc. (File No. 001-16169, Form 8-K dated April 28, 2011, Exhibit No. 2-1)

2-4		Distribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Constellation Energy Group, Inc. and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-3).

2-5		Contribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Energy Delivery Company, LLC and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-4).

2-6		Contribution Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Ventures Company, LLC and Exelon Generation Company, LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-5).

2-7		Purchase Agreement dated as of August 8, 2012 by and between Constellation Power Source Generation, Inc. and Raven Power Holdings, LLC (File No. 333-85496, Form 10-Q for the quarter ended September 30, 2012, Exhibit No. 2-1).

2-8		Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, filed by Constellation, File Nos. 1-12869 and 1-1910.)

2-9		Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, filed by Constellation, File Nos. 1-12869 and 1-1910.)

2-10		Asset Purchase Agreement, dated as of August 7, 2010, by and among EBG Holdings LLC, Boston Generating, LLC, Mystic I, LLC, Fore River Development, LLC, BG Boston Services, LLC, BG New England Power Services, Inc., Constellation Holdings, Inc. and Constellation Energy Group, Inc. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated August 11, 2010, filed by Constellation, File No. 1-12869.)

2-11		Master Agreement, dated as of October 26, 2010, by and between Electricite de France, S.A. and Constellation Energy Group, Inc. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 1, 2010, filed by Constellation, File No. 1-12869.)

2-12		Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 8, 2010, filed by Constellation, File No. 1-12869.)

452


Exhibit No.		Description
2-13		Contribution Agreement, dated as of February 4, 2010, by and among Constellation Energy Group, Inc., Baltimore Gas and Electric Company and RF HoldCo LLC. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated February 4, 2010, filed by Constellation, File Nos. 1-12869 and 1-1910.)

2-14		Purchase Agreement, dated as of February 4, 2010, by and between RF HoldCo LLC and GSS Holdings (Baltimore Gas and Electric Company Utility), Inc. (Designated as Exhibit No. 99.3 to the Current Report on Form 8-K dated February 4, 2010, filed by Constellation, File Nos. 1-12869 and 1-1910.

3-1		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).

3-2		Exelon Corporation Amended and Restated Bylaws, effective as of March 12, 2012 (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit 3-1).

3-3		Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).

3-4		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).

3-5		Restated Articles of Incorporation of Commonwealth Edison Company Effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 Cumulative Preference Stock” (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2).

3-6		Commonwealth Edison Company Amended and Restated By-Laws, Effective January 23, 2006 As Further Amended January 28, 2008 and July 27, 2009. (File No. 001-16169, Form 8-K dated July 27, 2009, Exhibit 3.1).

3-7		Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).

3-8		PECO Energy Company Amended Bylaws (File 000-16844, Form 8-K dated May 6, 2009, Exhibit 99.1).

3-9		Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated February 4, 2010, filed by Constellation, File No. 1-1910.)

3-10		Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, filed by Constellation, File No. 1-1910.)

3-11		Bylaws of Baltimore Gas and Electric Company, as amended to February 4, 2010. (Designated as Exhibit No. 3.2 to the Current Report on Form 8-K dated February 4, 2010, filed by Constellation, File No. 1-1910.)

3-12		Operating Agreement, dated as of February 4, 2010, by and among RF HoldCo LLC, Constellation Energy Group, Inc. and GSS Holdings (Baltimore Gas and Electric Company Utility), Inc. (Designated as Exhibit No. 99.1 to the Current Report on Form 8-K dated February 4, 2010, filed by Constellation, File Nos. 1-12869 and 1-1910.)

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).

453


Exhibit No.	Description
4-1-1	Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage:

	Dated as of	File Reference	Exhibit No.
	May 1, 1927	2-2881	B-1(c)

	March 1, 1937	2-2881	B-1(g)

	December 1, 1941	2-4863	B-1(h)

	November 1, 1944	2-5472	B-1(i)

	December 1, 1946	2-6821	7-1(j)

	September 1, 1957	2-13562	2(b)-17

	May 1, 1958	2-14020	2(b)-18

	March 1, 1968	2-34051	2(b)-24

	March 1, 1981	2-72802	4-46

	March 1, 1981	2-72802	4-47

	December 1, 1984	1-01401, 1984 Form 10-K	4-2(b)

	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

	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

	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

	September 1, 2012	000-16844, Form 8-K dated September 17, 2012	4.1

	October 1, 2012	000-16844, Form 8-K dated October 1, 2012	4.1

454


Exhibit No.	Description
4-2	Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-183751, 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. (Registration No. 2-60201, Form S-7, Exhibit 2-1).

4-3-1	Supplemental Indentures to Commonwealth Edison Company Mortgage.

	Dated as of	File Reference	Exhibit No.
	August 1, 1946	2-60201, Form S-7	2-1

	April 1, 1953	2-60201, Form S-7	2-1

	March 31, 1967	2-60201, Form S-7	2-1

	April 1,1967	2-60201, Form S-7	2-1

	February 28, 1969	2-60201, Form S-7	2-1

	May 29, 1970	2-60201, Form S-7	2-1

	June 1, 1971	2-60201, Form S-7	2-1

	April 1, 1972	2-60201, Form S-7	2-1

	May 31, 1972	2-60201, Form S-7	2-1

	June 15, 1973	2-60201, Form S-7	2-1

	May 31, 1974	2-60201, Form S-7	2-1

	June 13, 1975	2-60201, Form S-7	2-1

	May 28, 1976	2-60201, Form S-7	2-1

	June 3, 1977	2-60201, Form S-7	2-1

	May 17, 1978	2-99665, Form S-3	4-3

	August 31, 1978	2-99665, Form S-3	4-3

	June 18, 1979	2-99665, Form S-3	4-3

	June 20, 1980	2-99665, Form S-3	4-3

	April 16, 1981	2-99665, Form S-3	4-3

	April 30, 1982	2-99665, Form S-3	4-3

	April 15, 1983	2-99665, Form S-3	4-3

	April 13, 1984	2-99665, Form S-3	4-3

	April 15, 1985	2-99665, Form S-3	4-3

	April 15, 1986	33-6879, Form S-3	4-9

	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

	June 1, 2002	333-99363, Form S-3	4-1-1(B)

	October 7, 2002	333-9715, Form S-4	4-1-3

455


	Dated as of	File Reference	Exhibit No.
	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

	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

	July 12, 2010	001-01839, Form 8-K dated August 2, 2010	4.1

	January 4, 2011	001-01839, Form 8-K dated January 18, 2011	4.1

	August 22, 2011	001-01839, Form 8-K dated September 7, 2011	4.1

	September 17, 2012	001-01839, Form 8-K dated October 1, 2012	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 (Registration No. 33-20619, Form S-3, Exhibit 4-13).

456


Exhibit No.		Description

4-5		Indenture dated December 19, 2003 between Generation and U.S. Bank National Association (File No. 333-85496, 2003 Form 10-K, Exhibit 4-6).

4-6		Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (File No. 0-16844, June 30, 2003 Form 10-Q, Exhibit 4.1).

4-7		Form of 4.25% Senior Note due 2022. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit 4.1).

4-8		Form of 5.60% Senior Note due 2042. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit 4.2).

4-9		Form of 2.80% Senior Note due 2022. (File 1-1910, Form 8-K dated August 17, 2012, Exhibit 4.1).

4-10		Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and U.S. Bank National Association, as Trustee, dated as of June 24, 2003 (File No. 0-16844, June 30, 2003 Form 10-Q, Exhibit 4.2).

4-11		PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust 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).

4-12		Indenture dated May 1, 2001 between Exelon and The Bank of New York Mellon Trust Company, National Association, as trustee (File No. 1-16169, June 30, 2005 Form 10-Q, Exhibit 4-10).

4-13		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).

4-14		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).

4-15		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).

4-16		Form of 5.20% Generation Senior Note due 2019 (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.1).

4-17		Form of 6.25% Generation Senior Note due 2039 (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.2).

4-18		Form of 4.00% Generation Senior Note due 2020 (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.1).

4-19		Form of 5.75% Generation Senior Note due 2041 (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.2).

4-20		Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, filed by Constellation, File No. 333-75217.)

457


Exhibit No.		Description
4-21		First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, filed by Constellation, File No. 333-102723.)

4-22		Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, filed by Constellation, File No. 333-135991.)

4-23		First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee, dated as of June 27, 2008. (Designated as Exhibit 4(a) to the Current Report on Form 8-K dated June 30, 2008, filed by Constellation, File No. 1-12869.)

4-24		Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed by Constellation, File Nos. 1-12869 and 1-1910.)

4-25		Indenture dated July 1, 1985, between Baltimore Gas and Electric Company and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, filed by Constellation, File No. 1-1910.)

4-26		Indenture and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee (including form of Baltimore Gas and Electric Company Officer’s Certificate and form of Senior Secured Bond) (Designated as Exhibit Nos. 4(u) and 4(u)(1) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, filed by Constellation, File Nos. 333-157637 and 333-157637-01.)

4-27		Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(b) to the Registration Statement on Form S-3 filed July 24, 2006, filed by Constellation, File No. 333-135991.)

4-28		Supplemental Indenture No. 1, dated as of October 1, 2009, to the Indenture and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, filed by Constellation, File Nos. 1-12869 and 1-1910.)

4-29		Baltimore Gas and Electric Company Deed of Easement and Right-of-Way Grant dated as of July 9, 2009 (Designated as Exhibit No. 4(u)(2) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, filed by Constellation, File Nos. 333-157637 and 333-157637-01.)

4-30		Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, filed by Constellation, File No. 1-1910.)

458


Exhibit No.		Description
4-31		Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit No. 4(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, filed by Constellation, File No. 1 1910.)

4-32		Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated June 30, 2008, filed by Constellation, File No. 1-12869.)

4-33		Amendment to Replacement Capital Covenant, dated as of March 12, 2012, amending the Replacement Capital Covenant, dated as of June 27, 2008 (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 99.4)

4-34		Officers’ Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc., with the form of Notes attached thereto. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated December 14, 2010, filed by Constellation, File No. 1-12869.)

4-35		Officers’ Certificate, November 16, 2011, establishing the 3.50% Notes due November 15, 2021 of Baltimore Gas and Electric Company, with the form of Notes attached thereto. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated November 16, 2011, filed by Constellation, File No. 1-1910.)

10-1		Exelon Corporation Deferred Non-Employee Directors’ Deferred Stock Unit Plan (As Amended and Restated Effective January 1, 2011). *

10-2		Exelon Corporation Retirement Program (As Amended and Restated Effective January 1, 2010).

10-3		Exelon Corporation Deferred Compensation Plan for Directors (as amended and restated Effective January 1, 2011). *

10-4		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).

10-5-1		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).

10-5-2		Forms of Transferable Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-2).

10-5-3		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).

10-6		Exelon Corporation Employee Savings Plan (As Amended and Restated Effective January 1, 2010) (File No. 1-16169, 2010 Form 10-K, Exhibit 10-6).

10-7		Exelon Corporation Cash Balance Pension Plan (As Amended and Restated Effective January 1, 2010) (File No. 1-16169, 2010 Form 10-K, Exhibit 10-7).

10-8		Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).

10-9		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).

10-10		Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12).

10-11		Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-13).

459


Exhibit No.		Description
10-12		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).

10-13		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).

10-14		Exelon Corporation Annual Incentive Plan for Senior Executives Effective January 1, 2004 (As Amended and Restated Effective January 1, 2009) * (File No. 001-16169, 2009 Form 10-K, Exhibit 10.21).

10-15		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).

10-16		Form of change in control employment agreement (amended and restated as of January 1, 2009) * (File No. 001-16169, 2008 Form 10-K, Exhibit 10.24).

10-17		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).

10-18		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).

10-19		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).

10-20		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).

10-21		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).

10-22		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).

10-23		Facility Credit Agreement, dated as of November 4, 2010, among Generation and UBS AG, Stamford Branch (File No. 333-85496, Form 8-K dated February 22, 2011, Exhibit No. 10-1).

10-24		Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 * (File No. 1-16169, 2006 Form 10-K, Exhibit 10-52).

10-25		First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 * (File No. 1-16169, 2006 Form 10-K, Exhibit 10-53).

10-26		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).

10-27		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).

10-28		Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-K, Exhibit 10-56).

10-29		Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-K, Exhibit 10-57).

10-30		Commonwealth Edison Company Long-Term Incentive Plan, Effective January 1, 2007 (File No. 1-16169, March 31, 2007 Form 10-Q, Exhibit 10-1).

460


Exhibit No.		Description
10-31		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).

10-32		Restricted stock unit award agreement (File 1-16169, Form 8-K dated August 31, 2007, Exhibit 99.1).

10-33		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).

10-34		Amendment No. 1 to Amended and Restated Trade Receivables Purchase and Sale Agreement among PECO Energy Company, Victory Receivables Corporation and The Bank of Tokyo-Mitsubishi UFJ, Ltd. (File 000-16844, Form 8-K dated September 17, 2009, Exhibit 10.1).

10-35		Third Amended and Restated Employment Agreement with John W. Rowe * (File 1-16169, Fork 8-K dated October 29, 2009, Exhibit 99.1).

10-36		Exelon Corporation 2011 Long-Term Incentive Plan (File No. 1-16169, Schedule 14A dated March 18, 2010, Appendix A).

10-37		Form of Change in Control Employment Agreement Effective February 10, 2011. *

10-38		Credit Agreement for $500,000,000 dated as of March 23, 2011 between Exelon Corporation and Various Financial Institutions (File No. 001-16169, Form 8-K dated March 23, 2011, Exhibit No. 10-2).

10-39		Credit Agreement for $5,300,000,000 dated as of March 23, 2011 between Exelon Generation Company, LLC and Various Financial Institutions (File No. 333-85496, Form 8-K dated March 23, 2011, Exhibit No. 10-3).

10-40		Credit Agreement for $600,000,000 dated as of March 23, 2011 between PECO Energy Company and Various Financial Institutions (File No. 000-16844, Form 8-K dated March 23, 2011, Exhibit No. 10-4).

10-41		Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, Various Financial Institutions, as Lenders, and JP Morgan Chase Bank, N.A., as Administrative Agent (File No. 000-01839, Form 8-K dated March 28, 2012, Exhibit No. 99-1).

10-42		Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-6).

10-43		Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated.* (Designated as Exhibit No. 10(b) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-44		Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated.* (Designated as Exhibit No. 10(c) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation, File Nos. 1-12869 and 1-1910.)

461


Exhibit No.		Description
10-45		Constellation Energy Group, Inc. Benefits Restoration Plan, amended and restated effective June 1, 2010.* (Designated as Exhibit No. 10(b) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-46		Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated.* (Designated as Exhibit No. 10(e) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation, File Nos. 1-12869 and 1-1910.).

10-47		Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated.* (Designated as Exhibit No. 10(f) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-48		Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated.* (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-49		Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated.* (Designated as Exhibit No. 10(a) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-50		Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated.* (Designated as Exhibit No. 10(b) to the Constellation Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-51		Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated.* (Designated as Exhibit 10(b) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-52		Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated.* (Designated as Exhibit 10(a) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-53		Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated.* (Designated as Exhibit 10(d) to the Constellation Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-54		Constellation Energy Group, Inc. Amended and Restated 2007 Long-Term Incentive Plan.* (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated June 4, 2010, filed by Constellation, File No. 1-12869.)

10-55		Form of Grant Agreement for Stock Units with Sales Restriction.* (Designated as Exhibit No. 10(x) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-56		Rate Stabilization Property Servicing Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as servicer (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated July 5, 2007, filed by Constellation, File No. 1-1910.)

462


Exhibit No.		Description
10-57		Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated July 5, 2007, filed by Constellation, File No. 1-1910.)

10-58		Second Amended and Restated Operating Agreement, dated as of November 6, 2009, by and among Constellation Energy Nuclear Group, LLC, Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Development Inc., and for certain limited purposes, E.D.F. International S.A. and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 12, 2009, filed by Constellation, File No. 1-12869.)

10-59		Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(s) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-60		Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(t) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation, File Nos. 1-12869 and 1-1910.)

10-61		Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation, File No. 1-12869.)

10-62		Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation, File No. 1-12869.)

10-63		Settlement Agreement between EDF Inc., Exelon Corporation, Exelon Energy Delivery Company, LLC, Constellation Energy Group, Inc. and Baltimore Gas and Electric Company dated January 16, 2012. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated January 19, 2012, File Nos. 1-12869 and 1-1910.)

12-1		Exelon Corporation Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preference Stock Dividends.

12-2		Exelon Generation Company, LLC Computation of Ratio of Earnings to Fixed Charges.

12-3		Commonwealth Edison Company Computation of Ratio of Earnings to Fixed Charges.

12-4		PECO Energy Company Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preference Stock Dividends.

12-5		Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preference Stock Dividends.

14		Exelon Code of Conduct, as amended March 12, 2012 (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 14-1).

		Subsidiaries

21-1		Exelon Corporation

463


Exhibit No.		Description
21-2		Exelon Generation Company, LLC

21-3		Commonwealth Edison Company

21-4		PECO Energy Company

21-5		Baltimore Gas and Electric 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

23-5		Baltimore Gas and Electric Company

		Power of Attorney (Exelon Corporation)

24-1		Ann C. Berzin

24-2		John A. Canning, Jr.

24-3		Christopher M. Crane

24-4		Yves C. de Balmann

24-5		Nicholas DeBenedictis

24-6		Nelson A. Diaz

24-7		Sue L. Gin

24-8		Paul L. Joskow

24-9		Robert J. Lawless

24-10		Richard W. Mies

24-11		William C. Richardson

24-12		Thomas J. Ridge

24-13		John W. Rogers, Jr.

24-14		Mayo A. Shattuck III

24-15		Stephen D. Steinour

24-16		Donald Thompson

		Power of Attorney (Commonwealth Edison Company)

24-17		James W. Compton

24-18		Christopher M. Crane

24-19		A. Steven Crown

24-20		Peter V. Fazio, Jr.

24-21		Sue L. Gin

24-22		Michael Moskow

24-23		Anne R. Pramaggiore

24-24		Jesse H. Ruiz

		Power of Attorney (PECO Energy Company)

24-25		Craig L. Adams

24-26		Christopher M. Crane

24-27		M. Walter D’Alessio

24-28		Nelson A. Diaz

464


Exhibit No.		Description
24-29		Charisse R. Lillie

24-30		Thomas J. Ridge

24-31		Ronald Rubin

		Power of Attorney (Baltimore Gas and Electric Company)

24-32		Christopher M. Crane

24-33		Michael E. Cryor

24-34		James R. Curtiss

24-35		Kenneth W. DeFontes, Jr.

24-36		Joseph Haskins, Jr.

24-37		Carla D. Hayden

		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, 2010 filed by the following officers for the following registrants:

31-1		Filed by Christopher M. Crane for Exelon Corporation

31-2		Filed by Jonathan W. Thayer for Exelon Corporation

31-3		Filed by Christopher M. Crane for Exelon Generation Company, LLC

31-4		Filed by Bryan P. Wright for Exelon Generation Company, LLC

31-5		Filed by Anne R. Pramaggiore for Commonwealth Edison Company

31-6		Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

31-7		Filed by Craig L. Adams for PECO Energy Company

31-8		Filed by Phillip S. Barnett for PECO Energy Company

31-9		Filed by Kenneth W. DeFontes Jr. for Baltimore Gas and Electric Company

31-10		Filed by Carim V. Khouzami for Baltimore Gas and Electric 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, 2010 filed by the following officers for the following registrants:

32-1		Filed by Christopher M. Crane for Exelon Corporation

32-2		Filed by Jonathan W. Thayer for Exelon Corporation

32-3		Filed by Christopher M. Crane for Exelon Generation Company, LLC

32-4		Filed by Bryan P. Wright for Exelon Generation Company, LLC

32-5		Filed by Anne R. Pramaggiore for Commonwealth Edison Company

32-6		Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company

32-7		Filed by Craig L. Adams for PECO Energy Company

32-8		Filed by Phillip S. Barnett for PECO Energy Company

32-9		Filed by Kenneth W. DeFontes Jr. for Baltimore Gas and Electric Company

32-10		Filed by Carim V. Khouzami for Baltimore Gas and Electric 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

465


Exhibit No.		Description

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.

466

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 21st day of February, 2013.


EXELON CORPORATION

By:		/s/ CHRISTOPHER M. CRANE
Name:		Christopher M. Crane
Title:		President 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 21st day of February, 2013.


Signature		Title

/s/ CHRISTOPHER M. CRANE Christopher M. Crane		President and Chief Executive Officer (Principal Executive Officer) and Director

/s/ JONATHAN W. THAYER Jonathan W. Thayer		Executive 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 Darryl M. Bradford, Attorney-in-Fact, on behalf of the following Directors on the date indicated:


Yves C. de Balmann Ann C. Berzin John A. Canning, Jr. Nicholas DeBenedictis Nelson A. Diaz Sue L. Gin Paul L. Joskow Robert J. Lawless		Richard W. Mies William C. Richardson Thomas J. Ridge John W. Rogers, Jr. Mayo A. Shattuck III Stephen D. Steinour Donald Thompson


By:	/s/ DARRYL M. BRADFORD	February 21, 2013
Name:	Darryl M. Bradford

467

SIGNATURES


EXELON GENERATION COMPANY, LLC

By:		/s/ CHRISTOPHER M. CRANE
Name:		Christopher M. Crane
Title:		President


Signature		Title

/s/ CHRISTOPHER M. CRANE Christopher M. Crane		President (Principal Executive Officer)

/s/ BRYAN P. WRIGHT Bryan P. Wright		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ ROBERT M. AIKEN Robert M. Aiken		Vice President and Controller (Principal Accounting Officer)

468

SIGNATURES


COMMONWEALTH EDISON COMPANY

By:		/s/ ANNE R. PRAMAGGIORE
Name:		Anne R. Pramaggiore
Title:		President and Chief Executive Officer


Signature		Title

/s/ ANNE R. PRAMAGGIORE Anne R. Pramaggiore		President and Chief Executive Officer (Principal Executive Officer) and Director

/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/ CHRISTOPHER M. CRANE Christopher M. Crane		Chairman and Director

/s/ DENIS P. O’BRIEN Denis P. O’Brien		Vice Chairman and Director

This annual report has also been signed below by Anne R. Pramaggiore, Attorney-in-Fact, on behalf of the following Directors on the date indicated:


James W. Compton A. Steven Crown Peter V. Fazio, Jr.		Sue L. Gin Michael Moskow Jesse H. Ruiz


By:	/s/ ANNE R. PRAMAGGIORE	February 21, 2013
Name:	Anne R. Pramaggiore

469

SIGNATURES


PECO ENERGY COMPANY

By:		/s/ CRAIG L. ADAMS
Name:		Craig L. Adams
Title:		Chief Executive Officer and President


Signature		Title

/s/ CRAIG L. ADAMS Craig L. Adams		Chief Executive Officer and President (Principal Executive Officer) and Director

/s/ PHILLIP S. BARNETT Phillip S. Barnett		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ SCOTT A. BAILEY Scott A. Bailey		Vice President and Controller (Principal Accounting Officer)

/s/ CHRISTOPHER M. CRANE Christopher M. Crane		Chairman and Director

/s/ DENIS P. O’BRIEN Denis P. O’Brien		Vice Chairman and Director

This annual report has also been signed below by Craig L. Adams, 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
Charisse R. Lillie


By:	/s/ CRAIG L. ADAMS	February 21, 2013
Name:	Craig L. Adams

470

SIGNATURES


BALTIMORE GAS AND ELECTRIC COMPANY

By:		/s/ KENNETH W. DEFONTES, JR.
Name:		Kenneth W. DeFontes Jr.
Title:		Chief Executive Officer and President


Signature		Title

/s/ KENNETH W. DEFONTES, JR. Kenneth W. DeFontes Jr.		Chief Executive Officer and President (Principal Executive Officer) and Director

/s/ CARIM V. KHOUZAMI Carim V. Khouzami		Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

/s/ DAVID M. VAHOS David M. Vahos		Vice President and Controller (Principal Accounting Officer)

/s/ CHRISTOPHER M. CRANE Christopher M. Crane		Chairman and Director

/s/ DENIS P. O’BRIEN Denis P. O’Brien		Vice Chairman and Director

This annual report has also been signed below by Kenneth W. DeFontes, Jr., Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Michael E. Cryor

James R. Curtiss

Joseph Haskins, Jr.

Carla D. Hayden


By:	/s/ KENNETH W. DEFONTES, JR.	February 21, 2013
Name:	Kenneth W. DeFontes, Jr.

471