Edgar Filing: EXELON CORP

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, 2014

¨	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
Corporate Units		New York
PECO ENERGY COMPANY:
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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


	Large Accelerated	Accelerated	Non-Accelerated	Small Reporting Company
Exelon Corporation	ü
Exelon Generation Company, LLC			ü
Commonwealth Edison Company			ü
PECO Energy Company			ü
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, 2014 was as follows:


Exelon Corporation Common Stock, without par value		$31,319,710,373
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, 2015 was as follows:


Exelon Corporation Common Stock, without par value		859,833,343
Exelon Generation Company, LLC		not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,950
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 2015 Annual Meeting of

Shareholders and the Commonwealth Edison Company 2015 information statement are

incorporated by reference in Part III.

Exelon Generation Company, LLC, PECO Energy Company 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		22
	Baltimore Gas and Electric Company		26
	Employees		31
	Environmental Regulation		31
	Executive Officers of the Registrants		38
ITEM 1A.	RISK FACTORS		42
ITEM 1B.	UNRESOLVED STAFF COMMENTS		69
ITEM 2.	PROPERTIES		70
	Exelon Generation Company, LLC		70
	Commonwealth Edison Company		73
	PECO Energy Company		73
	Baltimore Gas and Electric Company		74
ITEM 3.	LEGAL PROCEEDINGS		76
	Exelon Corporation		76
	Exelon Generation Company, LLC		76
	Commonwealth Edison Company		76
	PECO Energy Company		76
	Baltimore Gas and Electric Company		76
ITEM 4.	MINE SAFETY DISCLOSURES		76

PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		77
ITEM 6.	SELECTED FINANCIAL DATA		80
	Exelon Corporation		80
	Exelon Generation Company, LLC		81
	Commonwealth Edison Company		82
	PECO Energy Company		83
	Baltimore Gas and Electric Company		83
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		85
	Exelon Corporation		85
	Executive Overview		85
	Critical Accounting Policies and Estimates		107
	Results of Operations		124
	Liquidity and Capital Resources		156
	Exelon Generation Company, LLC		192
	Commonwealth Edison Company		194
	PECO Energy Company		196
	Baltimore Gas and Electric Company		198


		Page No.
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		180
	Exelon Corporation		180
	Exelon Generation Company, LLC		180
	Commonwealth Edison Company		181
	PECO Energy Company		182
	Baltimore Gas and Electric Company		182
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		200
	Exelon Corporation		200
	Exelon Generation Company, LLC		201
	Commonwealth Edison Company		202
	PECO Energy Company		203
	Baltimore Gas and Electric Company		204
	Combined Notes to Consolidated Financial Statements		242
	1. Significant Accounting Policies		242
	2. Variable Interest Entities		257
	3. Regulatory Matters		265
	4. Merger and Acquisitions		298
	5. Investment in CENG		307
	6. Accounts Receivable		311
	7. Property, Plant and Equipment		312
	8. Impairment of Long Lived Assets		315
	9. Jointly Owned Electric Utility Plant		318
	10. Intangible Assets		319
	11. Fair Value of Financial Assets and Liabilities		324
	12. Derivative Financial Instruments		340
	13. Debt and Credit Agreements		357
	14. Income Taxes		368
	15. Asset Retirement Obligations		377
	16. Retirement Benefits		386
	17. Severance		405
	18. Preferred and Preference Securities		407
	19. Common Stock		408
	20. Earnings Per Share and Equity		415
	21. Changes in Accumulated Other Comprehensive Income		416
	22. Commitments and Contingencies		420
	23. Supplemental Financial Information		443
	24. Segment Information		451
	25. Related Party Transactions		456
	26. Quarterly Data		465
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		468
ITEM 9A.	CONTROLS AND PROCEDURES		468
	Exelon Corporation		468
	Exelon Generation Company, LLC		468
	Commonwealth Edison Company		468
	PECO Energy Company		468
	Baltimore Gas and Electric Company		468
ITEM 9B.	OTHER INFORMATION		469
	Exelon Corporation		469
	Exelon Generation Company, LLC		469
	Commonwealth Edison Company		469
	PECO Energy Company		469
	Baltimore Gas and Electric Company		469


		Page No.
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		470
ITEM 11.	EXECUTIVE COMPENSATION		471
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		472
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		473
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		474

PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		475

SIGNATURES			509
	Exelon Corporation		509
	Exelon Generation Company, LLC		510
	Commonwealth Edison Company		511
	PECO Energy Company		512
	Baltimore Gas and Electric Company		513

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.
Antelope Valley, AVSR		Antelope Valley Solar Ranch One
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
ComEd Financing III		ComEd Financing III
PEC L.P.		PECO Energy Capital, L.P.
PECO Trust III		PECO Energy Capital Trust III
PECO Trust IV		PECO Energy Capital Trust IV
BGE Trust II		BGE Capital Trust II
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
CAMR		Federal Clean Air Mercury Rule
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended


Other Terms and Abbreviations
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
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
DC Circuit Court		United States Court of Appeals for the District of Columbia Circuit
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
EGR		ExGen Renewables I, LLC
EGS		Electric Generation Supplier
EGTP		ExGen Texas Power, LLC
EIMA		Illinois Energy Infrastructure Modernization Act
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
GDP		Gross Domestic Product
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
Integrys		Integrys Energy Services, Inc.
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service


Other Terms and Abbreviations
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
LTIP		Long-Term Incentive Plan
MATS		U.S. EPA Mercury and Air Toxics Standard Rule
MBR		Market Based Rates Incentive
MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MGP		Manufactured Gas Plant
MISO		Midcontinent Independent System Operator, Inc.
mmcf		Million Cubic Feet
Moody’s		Moody’s Investor Service
MOPR		Minimum Offer Price Rule
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 including the CENG units (Calvert Cliffs, Nine Mile Point, and R.E. Ginna),Clinton, Oyster Creek, Three Mile Island, Zion (a former ComEd unit), and portions of Peach Bottom (a former PECO unit)
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


Other Terms and Abbreviations
POR		Purchase of Receivables
PPA		Power Purchase Agreement
PPL		PPL Holtwood, LLC
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 including the former ComEd units (Braidwood, Byron, Dresden, LaSalle, Quad Cities) and the former PECO units (Limerick, Peach Bottom, Salem)
RES		Retail Electric Suppliers
RFP		Request for Proposal
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
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
SOA		Society of Actuaries
SOS		Standard Offer Service
SPP		Southwest Power Pool
Tax Relief Act of 2010		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
Upstream		Natural gas and oil 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

This Report contains certain 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 Registrants include those factors discussed herein, including those factors discussed 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 and (c) ITEM 8. Financial Statements and Supplementary Data: Note 22; and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The public may read and copy any reports or other information that 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 Generation, in the energy generation business, and through 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 the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services, and engages in natural gas and oil exploration and production activities (Upstream). 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 electricity 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 electricity 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 natural 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 electricity 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 natural 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 24—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on Exelon’s operating segments.

Pending Merger with Pepco Holdings, Inc.

On April 29, 2014, Exelon and PHI signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. The merger is expected to be completed in the second or third quarter of 2015. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the pending transaction.

Generation

Generation, one of the largest competitive electric generation companies in the United States as measured by owned and contracted MW, physically delivers and markets power across multiple geographic regions through its customer-facing business, Constellation. Constellation sells electricity and natural gas to both wholesale and retail customers. The retail sales include commercial, industrial and residential customers. Generation’s electricity generation strategy is to pursue opportunities that provide generation-to-load matching and that diversify the generation fleet by expanding Generation’s regional and technological footprint. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation’s customer facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation’s fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the challenging conditions emanating from competitive energy markets. Generation’s customers include distribution utilities, municipalities, cooperatives, financial institutions, and commercial, industrial, governmental, and residential customers in competitive markets. Generation also sells renewable energy and other energy-related products and services, and engages in natural gas and oil exploration and production activities (Upstream).

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 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 to that performed by RTOs in markets regulated by FERC. 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 and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. PJM, MISO, ISO-NE and SPP, have been approved by FERC as RTOs, and CAISO and ISO-NY have been approved as ISOs. 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.

Merger with Constellation Energy Group, Inc.

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. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the Constellation merger.

Constellation Energy Nuclear Group, Inc.

Generation 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 a total of five nuclear generating facilities on three sites, Calvert Cliffs, R.E. Ginna and Nine Mile Point. CENG’s ownership share in the total capacity of these units is 3,998 MW. See ITEM 2. PROPERTIES for additional information on these sites.

Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s and Generation’s Consolidated Balance Sheets. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for further information regarding the integration transaction.

Significant Acquisitions

Integrys Energy Services, Inc. On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $332 million, including net working capital. The generation and solar asset businesses of Integrys are excluded from the transaction. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the above acquisition.

Antelope Valley Solar Ranch One. On September 30, 2011, Exelon announced the completion of its acquisition of all of the interests in Antelope Valley, a 242-MW solar project under development in northern Los Angeles County, California, from First Solar, Inc. The facility became fully operational in 2014. The project has a 25-year PPA with Pacific Gas & Electric Company for the full output of the plant, which has been approved by the CPUC. Total capitalized costs for the facility incurred as of December 31, 2014 were approximately $1.1 billion.

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 704 MWs.

Significant Dispositions

Asset Divestitures. As of December 31, 2014, Generation sold or entered into agreements to divest certain generating assets with total expected pre-tax proceeds of $1.8 billion (after-tax proceeds of approximately $1.4 billion). The proceeds are expected to be used primarily to finance a portion of the acquisition of PHI.

Maryland Clean Coal Stations. On November 30, 2012, a subsidiary of Generation sold the Brandon Shores generating station and H.A. Wagner generating station in Anne Arundel County, Maryland, and the C.P. Crane generating station in Baltimore County, Maryland to Raven Power Holdings LLC, a subsidiary of Riverstone Holdings LLC to comply with certain of the regulatory approvals required by the merger with Constellation Energy Group, Inc. for net proceeds of approximately $371 million, which resulted in a pre-tax impairment charge of $272 million.

See Note 4—Mergers, Acquisitions, and Dispositions and Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Generating Resources

At December 31, 2014, the generating resources of Generation consisted of the following:


Type of Capacity	MW
Owned generation assets^(a)(b)
Nuclear		19,316
Fossil ^(c)		9,515
Renewable ^(d)		3,434

Owned generation assets		32,265
Long-term power purchase contracts		9,574

Total generating resources		41,839

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

(b)	Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.

(c)	Comprised primarily of natural gas generating assets. Excludes Quail Run, which was sold on January 21, 2015.

(d)	Includes hydroelectric, wind, and solar generating assets.

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 35% of capacity).

•

Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee; and the United States footprint of MISO (excluding MISO’s Southern Region), 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 38% of capacity).

•

New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont (approximately 7% 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 6% of capacity).

See Note 24—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on revenues from external customers and revenues net of purchased power and fuel expense for each of Generation’s reportable segments.

Nuclear Facilities

Generation has ownership interests in fourteen nuclear generating stations currently in service, consisting of 24 units with an aggregate of 19,316 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), which are consolidated on Exelon’s and Generation’s financial statements relative to its proportionate ownership interest in each unit. In addition, Generation owns a 50.01% interest, collectively, in the CENG generating stations (Calvert Cliff Nuclear Power Plant, Nine Mile Point Nuclear Station [excluding LIPA’s 18% ownership interest in Nine Mile Point Unit 2] and R.E. Ginna) which are 100% consolidated on Exelon and Generation’s financial statements as of April 1, 2014. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for additional information.

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 2014, 2013, and 2012 electric supply (in GWh) generated from the nuclear generating facilities was 67%, 57% and 53%, 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.

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 2014 and 2013, the nuclear generating facilities operated by Generation achieved capacity factors of 94.3% and 94.1%, respectively. The capacity factors reflect ownership percentage of stations operated by Generation and include CENG as of April 1, 2014. 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, 2014, the NRC categorized Calvert Cliffs unit 2, Clinton, Limerick units 1 and 2, and Oyster Creek in the Regulatory Response Column, which is the second highest of five performance bands. All other units operated by Generation are categorized in the Licensee Response Column as of December 31, 2014, which is the highest performance band. 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. In July 2011, an NRC Task Force formed in the aftermath of the Fukushima Daiichi events 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 NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. The NRC and its staff are continuing to evaluate additional requirements. 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 Unit 1, Calvert Cliffs Units 1 and 2, Nine Mile Point Units 1 and 2, R.E. Ginna Unit 1, Three Mile Island Unit 1 and Limerick Units 1 and 2. Additionally, PSEG has 40-year operating licenses from the NRC and has received 20-year operating license renewals for Salem Units 1 and 2. On December 8, 2010, 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^(b)		1		1988		2026
		2		1988		2027
Byron^(b)		1		1985		2024
		2		1987		2026
Calvert Cliffs^(c)		1		1975		2034
		2		1977		2036
Clinton		1		1987		2026
Dresden^(c)		2		1970		2029
		3		1971		2031
LaSalle^(d)		1		1984		2022
		2		1984		2023
Limerick^(c)		1		1986		2044
		2		1990		2049
Nine Mile Point^(c)		1		1969		2029
		2		1988		2046
Oyster Creek^(c)(e)		1		1969		2029
Peach Bottom^(c)		2		1974		2033
		3		1974		2034
Quad Cities^(c)		1		1973		2032
		2		1973		2032
R.E. Ginna^(c)		1		1970		2029
Salem^(c)		1		1977		2036
		2		1981		2040
Three Mile Island^(c)		1		1974		2034

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

(b)	In May 2013, Generation submitted applications to the NRC to extend the operating licenses of Braidwood Units 1 and 2 and Byron Units 1 and 2 by 20 years.

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

(d)	In December 2014, Generation submitted applications to the NRC to extend the operating licenses of LaSalle Units 1 and 2 by 20 years.

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

Generation currently has license renewal applications pending for Braidwood Units 1 and 2, Byron Units 1 and 2, and LaSalle Units 1 and 2. Generation has advised the NRC that any license renewal application for Clinton would not be filed until the first quarter of 2021. 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 operating 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. When economically viable, 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. Based on ongoing reviews, the nuclear uprate implementation plan was adjusted during 2013 to cancel certain projects. The Measurement Uncertainty Recapture uprate projects at the Dresden and Quad Cities nuclear stations were cancelled as a result of the cost of additional plant modifications identified during final design work which, when combined with then current market conditions, made the projects not economically viable. Additionally, the market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. During 2013, Generation recorded a pre-tax charge to operating and maintenance expense and interest expense of approximately $111 million and $8 million, respectively, to accrue remaining costs and reverse the previously capitalized costs.

Under the nuclear uprate program, Generation has placed into service projects representing 393 MWs of new nuclear generation at a cost of $1,193 million, which has been capitalized to property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. At December 31, 2014, Generation has capitalized $122 million to construction work in progress within property, plant and equipment for nuclear uprate projects expected to be placed in service by the end of 2016, consisting of 139 MWs of new nuclear generation that is in the installation phase at one nuclear station, Peach Bottom in Pennsylvania. The remaining spend associated with this project is expected to be approximately $125 million through the end of 2016. Generation believes that it is probable that this project will be completed. If a project is expected not to be completed as planned, previously capitalized costs will be reversed through earnings as a charge to operating and maintenance expense and interest.

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, 2014, Generation had approximately 73,800 SNF assemblies (18,300 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 15—Asset Retirement Obligations 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 are anticipated to 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 is expected to be in operation at Three Mile Island prior to losing full core offload capability in 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 22—Commitments and Contingencies 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 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 such an agreement, although neither state currently has an operational site and none is anticipated to be operational until after 2020.

Generation ships its Class A LLRW, which represents 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 utilizes on-site storage capacity at its Peach Bottom and LaSalle stations to store Class B and Class C LLRW for all stations in Generation’s nuclear fleet, as approved by the NRC. Generation has a contract through 2032 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently stored at the Peach Bottom and LaSalle stations as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW from Generation’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still be required to utilize on-site storage at its Peach Bottom and LaSalle stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store all Class B and C LLRW for the life of all stations in Generation’s nuclear fleet. 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 major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 22—Commitments and Contingencies 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 Note 3—Regulatory Matters, Note 11—Fair Value of Financial Assets and Liabilities and Note 15—Asset Retirement Obligations 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 ARO liabilities to

decommission Dresden Unit 1 and Peach Bottom Unit 1 as of December 31, 2014 were $188 million and $111 million, respectively. As of December 31, 2014, NDT funds set aside to pay for these obligations were $459 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 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, excluding the obligation to dispose of SNF, associated with Zion Station. Pursuant to the ASA, ZionSolutions will 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 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning and see Note 2—Variable Interest Entities 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 12,949 MW of capacity in fossil and renewable generating facilities currently in service (excluding Quail Run, which was sold on January 21, 2015). Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) jointly owned facilities that include Wyman; (2) an ownership interest through an equity method investment in Sunnyside; and (3) certain wind project entities with minority interest owners, see Note 2—Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information on these wind project entities. Generation’s fossil and renewable generating stations are all operated by Generation, with the exception of LaPorte, Sunnyside and Wyman, which are operated by third parties. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information relating to the sale of the Quail Run generating facility. In 2014 and 2013, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 13% and 15%, 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—Exelon Generation Company, LLC and ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Exelon Corporation, Executive Overview for additional information on Generation Renewable Development.

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 Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively. Based on the FERC procedural schedule, the FERC licensing process was not completed prior to the expiration of Muddy Run’s license on August 31, 2014, and the expiration of Conowingo’s license on September 1, 2014. FERC is required to issue annual licenses for the facilities

until the new licenses are issued. On September 10, 2014, FERC issued annual licenses for Conowingo and Muddy Run, effective as of the expiration of the previous licenses. If FERC does not issue new licenses prior to the expiration of annual licenses, the annual licenses will renew automatically. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. Refer to Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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, unless required by financing agreements. 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—Exelon Generation Company, LLC.

Long-Term Power Purchase Contracts

In addition to energy produced by owned generation assets, Generation sources electricity and other related output from plants it does not own 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, 2014:


Region	Number of Agreements		Expiration Dates	Capacity (MW)
Mid-Atlantic		19	2015 - 2032		860
Midwest		7	2015 - 2022		1,734
New England		15	2015 - 2020		1,401
ERCOT		5	2020 - 2031		1,534
Other Regions		15	2015 - 2030		4,045

Total		61			9,574


	2015		2016		2017		2018		2019
Capacity Expiring (MW)		2,726		73		1,965		101		631

Fuel

The following table shows sources of electric supply in GWh for 2014 and 2013:


	Source of Electric Supply
	2014		2013
Nuclear ^(a)		166,454		142,126
Purchases—non-trading portfolio^(b)		48,200		69,791
Fossil (primarily natural gas)		26,324		30,785
Renewable ^(c)		6,429		6,420

Total supply		247,407		249,122

(a)

Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g., CENG). Nuclear generation for 2014 and 2013 includes physical volumes of 25,053 GWh and 0 GWh, respectively, for CENG.

(b)	Purchased power for 2014 and 2013 includes physical volumes of 5,346 GWh and 24,232 GWh, respectively, as a result of the PPA with CENG. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, 100% of CENG volumes are included in nuclear generation.

(c)	Includes hydroelectric, wind, and solar generating assets.

The fuel costs per MWh for nuclear generation are less than those 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 2015. All of Generation’s enrichment requirements have been contracted through 2020. 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, as well as 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.

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 12—Derivative Financial Instruments 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, including tolling agreements, 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 also buy power to meet the energy demand of its customers. 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. Additionally, Generation is involved in the development, exploration, and harvesting of oil, natural gas and natural gas liquids properties (Upstream).

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 commodity price risk in 2015 and beyond for portions of its electricity portfolio that are unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years. This strategy has not changed as a result of recent and pending asset divestitures. As of December 31, 2014, the percentage of expected generation hedged for the major reportable segments was 93%-96%, 61%-64% and 31%-34% for 2015, 2016, and 2017, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation (which reflects the divestiture impact of Quail Run). Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. 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. The corporate risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retail power marketing activities. 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 proprietary 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. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

At December 31, 2014, 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:


(in millions)	Net Capacity Purchases ^(a)		REC Purchases ^(b)		Transmission Rights Purchases ^(c)		Total
2015	$	418	$	152	$	20	$	590
2016		283		228		15		526
2017		222		121		15		358
2018		112		29		16		157
2019		117		5		16		138
Thereafter		279		1		35		315

Total	$	1,431	$	536	$	117	$	2,084

(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, 2014, net of fixed capacity payments expected to be received (“Capacity offsets”) by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of December 31, 2014, capacity offsets were $132 million, $133 million, $136 million, $137 million,$138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.

(b)	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.

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 2015 are as follows:


(in millions)
Nuclear fuel^(a)	$	1,250
Production plant		1,800
Renewable energy projects		225
Maryland commitments		225
Other		125

Total	$	3,625

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

ComEd

ComEd is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity 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 2015 to 2066. ComEd anticipates working with the appropriate governmental bodies 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 6, 2014, and was 16,515 MWs.

Retail Electric Services

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 a competitive electric generation supplier. The number of retail customers

participating in customer choice programs was 2,426,921, 2,630,185 and 1,627,150 at December 31, 2014, 2013 and 2012, respectively, representing 63.0%, 68% and 43% of total retail customers, respectively. Retail energy purchased from competitive electric generation suppliers represented 80%, 81% and 65% of ComEd’s retail kWh sales for the years ended December 31, 2014, 2013 and 2012, respectively.

The customers’ 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 or ComEd’s financial position. ComEd’s cost of electric supply is passed without markup directly through to those customers not served by a competitive electric generation supplier 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 Note 24—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on revenues from external customers, net income and total assets.

Under Illinois law, ComEd is required to deliver electricity to all customers within ComEd’s service territory. 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 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.

EIMA is scheduled to sunset, ending ComEd’s performance based rate formula and investment commitment, at December 31, 2017, unless approved to continue through 2022 by the Illinois General Assembly. During the fourth quarter of 2014, the Illinois House and Senate each passed House Bill 3975 which extends the date of the EIMA sunset from 2017 to 2019. The bill was presented to the Governor on February 11, 2015. The Governor can either act on the bill or, after 60 days, the bill will automatically become law.

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. ComEd’s allowed rate of return on common equity is the annual average rate on 30-year treasury notes plus 580 basis points, subject to a (collar) of plus or minus 50 basis points. The collar, therefore limits favorable and unfavorable impacts of weather and load on distribution revenue. In addition, ComEd’s allowed 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—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Procurement-Related Proceedings. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. 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. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on ComEd’s Statement of operations and Comprehensive Income.

See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s procurement plans.

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 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Smart Meter, Smart Grid and Energy Efficiency

Smart Meter and Smart Grid Programs. 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. On June 11, 2014, the ICC approved ComEd’s request to accelerate the deployment, which allows for the installation of more than four million smart meters throughout ComEd’s service territory by 2018, three years in advance of the originally scheduled 2021 completion date. To date, nearly 550,000 smart meters have been installed in the Chicago area by ComEd.

Energy Efficiency Programs. 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 January 2014, the ICC approved ComEd’s third three-year Energy Efficiency and Demand Response Plan covering the period June 2014 through May 2017. The plans are designed to meet Illinois’ energy efficiency and demand response goals through May 2017, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers.

EIMA provides for additional energy efficiency in Illinois. Starting in the June 2013 through May 2014 period and occurring annually thereafter, as part of the IPA procurement plan, ComEd is to include cost-effective expansion of current energy efficiency programs, and additional new cost-effective and/or third-party energy efficiency programs that are identified through a request for proposal process. All cost-effective energy efficiency programs are included in the IPA procurement plan for consideration of implementation. While these programs are monitored separately from the Energy Efficiency Portfolio Standard (EEPS), funds for both the EEPS portfolio and IPA energy efficiency programs are collected under the same rider.

Construction Budget

ComEd’s business is capital intensive and requires significant investments, primarily in electricity transmission and electricity distribution facilities, to ensure the adequate capacity, reliability and efficiency of its system. Such investments include capital program and modernization pursuant to EIMA, and transmission upgrades and expansion including the Grand Prairie Gateway Transmission Line project, and PJM’s RTEP. ComEd’s most recent estimate of capital expenditures for electric plant additions and improvements for 2015 is $2,200 million.

See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional details. 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 electricity 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 4.0 million, including approximately 1.6 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 506,000 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,” with all of such 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 January 7, 2014 and was 7,166 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 7, 2014 and was 760 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 competitive electric generation suppliers for the supply of retail electricity while retail transmission and distribution service remains regulated under the Competition Act. At December 31, 2014, there were 101 competitive electric generation suppliers serving PECO customers. At December 31, 2014, the number of retail customers purchasing energy from a competitive electric generation supplier was 546,900 representing approximately 34% of total retail customers. Retail deliveries purchased from competitive electric generation suppliers represented approximately 70% of PECO’s retail kWh sales for the year ended December 31, 2014. Customers that choose a competitive electric generation supplier 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 competitive electric generation suppliers.

Customer choice program activity affects revenue collected from customers related to supplied energy; however, that activity has no impact on PECO’s electric revenue net of purchased power expense or 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 a competitive electric generation supplier, PECO acts as the billing agent but does not record revenue or purchased power 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.

See Note 24—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on revenues from external customers, net income and total assets.

Procurement-Related Proceedings. PECO’s electric supply for its customers is procured through contracts executed in accordance with its PAPUC-approved DSP Programs.

On October 12, 2012, the PAPUC approved PECO’s second DSP Program, which was filed with the PAPUC in January 2012. The plan outlined how PECO purchased electric supply for default service customers from June 1, 2013 through May 31, 2015. Pursuant to the second DSP Program, PECO procured 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. PECO entered into contracts with PAPUC approved bidders, including Generation, for its five competitive procurements. 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.

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 competitive electric generation suppliers beginning April 1, 2014. On May 1, 2013, PECO filed a Petition for Approval of its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court’s review, PECO will not implement CAP Shopping. The Commonwealth Court’s decision is expected in 2015.

On March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. On August 28, 2014, PECO filed a Joint Petition for Partial Settlement, which affirmed PECO’s procurement plan for residential and small commercial customers. On December 4, 2014, the PAPUC approved PECO’s third DSP Program, as modified by the Joint Petition for Partial Settlement, without modification or limitation. Separate from the Joint Petition for Partial Settlement, the PAPUC also approved other items related to the program. The plan outlines how PECO will purchase electric supply for default service customers. PECO will procure electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load.

See Note 3—Regulatory Matters 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 was awarded $200 million, the maximum grant allowable under the program, for its SGIG project—Smart Future Greater Philadelphia. As of December 31, 2014, PECO has received all of the $200 million, including $4 million for sub-recipients, in reimbursements. The SGIG funds have been used by PECO to offset the total impact to ratepayers of the smart meter deployment required by Act 129. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC, which was approved without modification on August 15, 2013. Under PECO’s universal deployment plan, PECO will deploy all of the 1.7 million electric smart meters on an accelerated basis by the second quarter of 2015. In total, PECO currently expects to spend up to $583 million and $155 million on its smart meter and smart grid infrastructure, respectively, before considering the $200 million SGIG funds. As of December 31, 2014, PECO has spent $540 million and $119 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received.

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

Energy Efficiency Programs. PECO’s PAPUC-approved Phase I EE&C plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I Plan set forth how PECO would meet the required reduction targets established by Act 129’s EE&C provisions, which included a 3.0% 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. On March 20, 2014, the PAPUC issued its final report stating that PECO was in full compliance with all Phase I targets.

The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provides energy consumption reduction requirements for the second phase of Act 129’s EE&C programs, which went into effect on June 1, 2013 with a three-year cumulative consumption reduction target of 1,125,852 MWh.

make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO’s EE&C Plan subsequent to its Phase II Plan.

On February 28, 2014, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with other Phase II Plan costs. The PAPUC granted PECO’s Petition in an Order that became final on May 5, 2014.

Pennsylvania Retail Electricity Market. The extreme weather experienced in early 2014 resulted in increased commodity costs causing certain shopping customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, on April 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electric generation suppliers to provide more consumer education regarding their contracts. The second rulemaking order requires electric distribution companies to enable customers to switch suppliers within three business days (known as accelerated switching). The improved customer education and accelerated switching were to be in place within 30 days and six months of approval of the orders, respectively. The orders became final on June 14, 2014. On December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on Supplier Switch), allowing PECO to implement accelerated switching by the December 15, 2014 deadline.

See Note 3—Regulatory Matters 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, 2014, the number of retail customers purchasing natural gas from a competitive natural gas supplier was 78,400, representing approximately 15% of total retail customers. Retail deliveries purchased from competitive natural gas suppliers represented approximately 22% of PECO’s mmcf sales for the year ended December 31, 2014. PECO provides distribution, billing, metering, installation, maintenance and emergency response services at regulated rates to all its customers in its service territory.

Procurement-Related 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 three years in accordance with its annual PAPUC PGC settlement. PECO’s aggregate annual firm supply under these firm transportation contracts is 32 million dekatherms. Peak natural gas is provided by PECO’s liquefied natural gas (LNG) facility and propane-air plant which provide 1.2 billion cubic feet and 181,441 dekatherms, respectively, on an annual basis. PECO also has under contract 21 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 29% of PECO’s 2014-2015 heating season planned supplies.

Gas Main Extension Program. On November 6, 2014, PECO filed a plan with the PAPUC requesting approval of three initiatives to provide more incentives to customers interested in switching to natural gas service. If approved, local customers would pay significantly less initially to have natural gas installed at their homes and businesses.

See Note 3—Regulatory Matters 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. PECO’s most recent estimate of capital expenditures for plant additions and improvements for 2015 is $550 million, which includes RTEP projects and capital expenditures related to the smart meter and smart grid project.

BGE

BGE is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity 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 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 800 square 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 rights are nonexclusive 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 January 7, 2014 and was 6,526 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 commercial 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 are 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 affected 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 a competitive electric generation supplier. 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 minimal impact on BGE’s electric revenue net of purchased power expense or financial position. At December 31, 2014, there were 59 competitive electric generation suppliers serving BGE customers. At December 31, 2014, the number of retail customers purchasing energy from a competitive electric generation supplier was approximately 364,000, representing 29% of total retail customers. Retail deliveries purchased from competitive electric generation suppliers represented approximately 60% of BGE’s retail kWh sales for the year ended December 31, 2014.

See Note 24—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on revenues from external customers, net income and total assets.

Procurement Related Proceedings. 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. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on BGE’s Statement of Operations and Comprehensive Income.

See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on BGE’s procurement plan.

Electric Distribution Rate Case. On July 2, 2014, and as amended on September 15, 2014, BGE filed for an electric base rate increase with the MDPSC, ultimately requesting an increase of $99 million. On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement (the

Settlement Agreement) reached with all parties to the case under which it would receive an increase of $22 million in electric base rates. The Settlement Agreement establishes new depreciation rates which have the effect of decreasing annual electric depreciation expense by approximately $22 million. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreement without modification, which became a final order on December 12, 2014. The approved electric distribution rate became effective for services rendered on or after December 15, 2014.

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

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 was awarded $200 million, the maximum grant allowable under the program, to support its Smart Grid, Peak Rewards and CC&B initiatives, of which BGE had been fully reimbursed for as of December 31, 2013. The SGIG funding significantly reduced the rate impact of those investments on BGE customers.

See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding BGE’s Smart Meter Programs.

Energy Efficiency Programs. BGE’s energy efficiency programs include a lighting program, retrofit programs, incentives for energy efficient new homes, rebates for heating and cooling systems, energy audits, an energy efficient appliance rebate and trade-in program, customer incentives for non-profit, educational, governmental and business customers, energy management programs and bill credits to help residential customers reduce energy demand during peak periods. The MDPSC initially approved a full portfolio of conservation programs in 2008 as well as a customer surcharge to recover the associated costs in 2009. This customer surcharge is updated annually. In December 2011, the MDPSC approved BGE’s conservation programs for implementation in 2012 through 2014. On December 23, 2014, the MDPSC approved BGE’s proposal for the 2015-2017 programs with minor modifications.

See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding BGE’s Energy Efficiency Programs.

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. 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.

Customer choice program activity affects revenue collected from customers related to supplied natural gas; however, that activity has minimal impact on BGE’s gas revenue net of purchased power expense or financial position. At December 31, 2014, there were 40 competitive natural gas suppliers serving BGE customers. At December 31, 2014, the number of retail customers purchasing fuel from a

competitive natural gas supplier was approximately 161,000 representing 25% of total retail customers. Retail deliveries purchased from competitive natural gas suppliers represented approximately 53% of BGE’s retail mmcf sales for the year ended December 31, 2014.

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 354 mmcf per day.

BGE’s current maximum storage entitlements are 312 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 1,055 mmcf and a daily capacity of 332 mmcf,

•

a liquefied natural gas facility for natural gas system pressure support with a total storage capacity of 6 mmcf and a daily capacity of 6 mmcf, and

•

a propane air facility and a mined cavern with a total storage capacity equivalent to 546 mmcf and a daily capacity of 85 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 Case. On July 2, 2014, and as amended on September 15, 2014, BGE filed for a gas base rate increase with the MDPSC, ultimately requesting an increase of $68 million. On October 17, 2014, BGE filed with the MDPSC the Settlement Agreement reached with all parties to the case under which it would receive an increase of $38 million in gas base rates. The Settlement Agreement establishes new depreciation rates which have the effect of increasing annual gas depreciation expense by approximately $2 million. On December 14, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreement without modification, which became a final order on December 12, 2014. The approved gas distribution rate became effective for services rendered on or after December 15, 2014.

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

Construction Budget

BGE’s business is capital intensive and requires significant investments primarily in electric and natural gas distribution and electric transmission 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 BGE’s most recent estimate of capital expenditures for plant additions and improvements for 2015 is approximately $700 million.

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 PECO’s 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—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding transmission services.

Employees

As of December 31, 2014, Exelon and its subsidiaries had 28,993 employees in the following companies, of which 9,276 or 32% 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^(e)		1,690		96		2,353		4,139		14,370
ComEd		3,739		—		—		3,739		6,403
PECO		—		1,282		—		1,282		2,458
BGE		—		—		—		—		3,252
Other^(d)		72		—		44		116		2,510

Total		5,501		1,378		2,397		9,276		28,993

(a)	A separate CBA between ComEd and IBEW Local 15 covers approximately 55 employees in ComEd’s System Services Group and expires in 2015. Generation’s and ComEd’s separate CBAs with IBEW Local 15 was renewed in 2014 and expires in 2019.

(b)	1,378 PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614. The CBAs expire in 2019. Additionally, Exelon Power, an operating unit of Generation, has an agreement with IBEW Local 614, which expires in 2016 and covers 96 employees.

(c)

During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively and CENG finalized its CBA with Nine Mile Point which will expire in 2020. Additionally, during 2014, Generation finalized CBAs with the Security Officer unions at Dresden, LaSalle, Limerick and Quad Cities, which expire between 2017 and 2018. Lastly, during 2014, an agreement was negotiated with Las Vegas District Energy and IUOE Local 501, which will expire in 2018. During 2013, two other 3-year agreements were negotiated: New England ENEH, UWUA Local 369, which will expire in 2017; and New Energy IUOE Local 95-95A, which will expire in 2016. 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 a CBA with the Security Officer unions at Braidwood, which expires in 2015.

(d)	Other includes shared services employees at BSC.

(e)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the total includes CENG employees as of December 31, 2014.

Environmental Regulation

General

Exelon, Generation, ComEd, PECO and BGE are subject to comprehensive and complex legislation regarding environmental matters by the federal government and 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 Exelon’s climate change and sustainability policies and programs, 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. The respective Boards of ComEd, PECO and BGE, which each include directors who also serve on the Exelon board, 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 (NOx), 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 reduce substantially air pollution from power plants.

See ITEM 7.—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding clean air regulation in the forms of the CSAPR, 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.

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. 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.

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 by changes to the existing regulations. 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 October 14, 2014, the U.S. EPA’s final Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available, followed by an implementation period. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.

The rule does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment of aquatic life at a facility’s cooling water intake structure. The rule provides the state permitting director with significant 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 rule also provides a number of flexible compliance options to reduce impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or other technology at the intake. A number of concerns raised by the electric generation industry about the proposed rule were resolved favorably in the final rule.

Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its and CENG’s generating facilities and its future results of operations, cash flows capital expenditures, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability would be called into question. However, the likely impact of the rule has been significantly decreased since the final rule does not mandate cooling towers as a national standard, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors.

New York Facilities. In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved. Each of CENG’s New York facilities received renewals of their SPDES permits in 2014.

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. However, it is unknown at this time whether implementation of the final EPA rule will result in a requirement to install closed cycle cooling at Salem.

Solid and Hazardous Waste

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, 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 22—Commitments and Contingencies 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 2015 at Exelon for compliance with environmental remediation related to contamination at former MGP sites is expected to total $35 million, consisting of $29 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, 2014, 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—Regulatory Matters and 22—Commitments and Contingencies 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 positions.

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 Intergovernmental Panel on Climate Change in their Fifth Assessment Report Summary for Policy Makers issued in September 2013. 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 2014, 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 2012 meeting of the United Nations Framework on Climate Change Conference of the Parties (COP 18). 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. This new global agreement for GHG emissions reductions was agreed to only in concept during the COP18, with a timeline for establishing the global targets by 2015. On November 22, 2013, at the 2013 COP 19 held in Warsaw, Poland, participating countries further agreed to provide their “intended nationally determined contributions” by the first quarter of 2015 in preparation for formally setting global target in 2015. At COP 20 held in Lima, Peru, in December 2014, participating countries outlined the universal GHG reduction agreement to be finalized in 2015 at COP 21 in Paris. On November 11, 2014, President Obama and President Xi Jinping of China jointly announced their respective “intended nationally determined contributions” for post 2020 greenhouse gas emission reductions. The US announced net greenhouse gas emission reductions of 26-28 percent below 2005 levels by 2025, while China announced targets to peak CO₂ emissions around 2030, and to increase the non-fossil fuel share of all energy to around 20 percent by 2030. Together, the U.S. and China account for over one–third of global greenhouse gas emissions.

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. In June 2013, the White House released the President’s Climate Action Plan which consists of a wide variety of executive actions targeting GHG reductions, preparing for the impacts of climate change and showing leadership internationally; but the plan did not directly trigger any new requirements or legislative action.

The U.S. EPA is addressing the issue of carbon dioxide (CO₂) emissions regulation for new and existing electric generating units through the New Source Performance Standards (NSPS) under Section 111 of the Clean Air Act. Pursuant to President Obama’s June 25, 2013 memorandum to U.S. EPA, the Agency re-proposed a Section 111(b) regulation for new units in September 2013 that may result in material costs of compliance for CO₂ emissions for new fossil-fuel electric generating units, particularly coal-fired units. Under the President’s memorandum, the U.S. EPA was also required to propose a Section 111(d) rule no later than June 1, 2014 to establish CO₂ emission regulations for existing stationary sources. The second rulemaking, under Section 111(d) of the Clean Air Act, focuses on modified, reconstructed and existing fossil power plants. The proposed rule was published in the Federal Register on June 18, 2014, and the public comment period closed on December 1, 2014. The Climate Action Plan calls for the rule to be finalized no later than June 1, 2015, and requires that states submit to U.S. EPA their implementation plans no later than June 30, 2016.

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 Regional Greenhouse Gas Reduction Initiative (RGGI) released an updated RGGI Model Rule and Program Review Recommendations Summary on February 7, 2013. Under the updated RGGI program the regional RGGI CO₂ budget was reduced, starting in 2014, from its previous 165 million ton level to 91 million tons, with a 25 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 trigger prices are $4 in 2014, $6 in 2015, $8 in 2016 and $10 in 2017, after 2017 the CCR price increases by 2.5 percent each year). Such an outcome could put modest upward pressure on wholesale power prices; however, the specifics are currently uncertain.

At the state level, 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 of Illinois are the energy efficiency and renewable portfolio standards in the Illinois Power Act that apply to ComEd.

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 was chartered in 2007 and released a 42 greenhouse gas reduction strategy, climate action plan, on August 27, 2008. The plan’s primary policy recommendation to formally 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) which requires Maryland to reduce its GHG emissions by 25 percent below 2006 levels by 2020. It also directed the Maryland Department of Environment to prepare and implement an action plan which was published in October of 2013. Maryland’s electricity consumption reduction goals, required under the “Empower Maryland” program, and mandatory State participation in RGGI Program, are listed as the energy sector’s contribution in the plan. The plan also advocated raising the renewable portfolio standard requirement from 20% by 2022 to 25% by 2022. The Department of Environment is required to submit a December 2015 report to the Governor and General Assembly on progress towards the 25% mandate; its costs and benefits; the need for target adjustments; and the status of federal programs. In 2016, the Legislature will review the progress report, its economic impacts on manufacturing sector and other information and determine whether to continue, adjust or eliminate the requirement to achieve a 25% reduction by 2020.

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.

Based on an independent third-party verification of Exelon’s GHG performance through year-end 2013, it achieved the Exelon 2020 goal of abating 17.5 million tonnes of GHG emissions annually, seven years ahead of plan. Exelon’s approach for addressing the issue of climate change is currently focused on continuing to manage its GHG emissions from internal operations, contributing to reducing overall grid GHG emissions and ensuring the resiliency of its infrastructure in response to the physical impacts of climate change.

Renewable and Alternative Energy Portfolio Standards

Thirty-nine states and the District of Columbia have adopted some form of RPS requirement. 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.

Illinois utilities are 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 by Illinois legislation. As of December 31, 2014, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois 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 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s procurement plans. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding ComEd’s future commitments for the procurement of RECs.

The AEPS Act became effective for PECO on January 1, 2011. During 2014, PECO was required to supply approximately 4.5% 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) through May 31, 2014 and subsequently 5.0% beginning June 1, 2014 and continuing through May 31, 2015. PECO was also required to supply 6.2% of electric energy generated from 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, 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 a phase out of Tier 2 resource options by 2022. In 2014, 10.3% was required from Tier 1 renewable sources, including at least 0.35% derived from solar energy, and 2.5% from Tier 2 renewable sources. 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 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—Regulatory Matters and Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Executive Officers of the Registrants as of February 13, 2015

Exelon


Name	Age		Position	Period
Crane, Christopher M.		56	Chief Executive Officer, Exelon;	2012 - Present
			Chairman, ComEd, PECO & BGE	2012 - Present
			President, Exelon	2008 - Present
			President, Generation	2008 - 2013
			Chief Operating Officer, Exelon	2008 - 2012
			Chief Operating Officer, Generation	2007 - 2010
Cornew, Kenneth W.		49	Senior Executive Vice President and Chief Commercial Officer, Exelon;	2013 - Present
			President and CEO, Generation	2013 - Present
			Executive Vice President and Chief Commercial Officer, Exelon	2012 - 2013
			President and Chief Executive Officer, Constellation	2012 - 2013
			Senior Vice President, Exelon; President, Power Team	2008 - 2012
O’Brien, Denis P.		54	Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities	2012 - Present
			Vice Chairman, ComEd, PECO, BGE	2012 - Present
			Chief Executive Officer, PECO; Executive Vice President, Exelon	2007 - 2012
			President and Director, PECO	2003 - 2012
Pramaggiore, Anne R.		56	Chief Executive Officer, ComEd	2012 - Present
			President, ComEd	2009 - Present
			Chief Operating Officer, ComEd	2009 - 2012
Adams, Craig L.		62	President and Chief Executive Officer, PECO	2012 - Present
			Senior Vice President and Chief Operating Officer, PECO	2007 - 2012
Butler, Calvin G.		45	Chief Executive Officer, BGE	2014 - Present
			Senior Vice President, Regulatory and External Affairs, BGE	2013 - 2014
			Senior Vice President, Corporate Affairs, Exelon	2011 - 2013
			Senior Vice President, Human Resources, Exelon	2010 - 2011
			Senior Vice President, Corporate Affairs, ComEd	2009 - 2010
Von Hoene Jr., William A.		61	Senior Executive Vice President and Chief Strategy Officer, Exelon	2012 - Present
			Executive Vice President, Finance and Legal, Exelon	2009 - 2012
Thayer, Jonathan W.		43	Senior Executive Vice President and Chief Financial Officer, Exelon	2012 - Present^(a)
			Senior Vice President and Chief Financial Officer, Constellation Energy; Treasurer, Constellation Energy	2008 - 2012
Aliabadi, Paymon		52	Executive Vice President and Chief Risk Officer, Exelon	2013 - Present
			Managing Director, Gleam Capital Management	2012 - 2013
			Principal and Managing Director, Gunvor International	2009 - 2011
DesParte, Duane M.		51	Senior Vice President and Corporate Controller, Exelon	2008 - Present

Generation


Name	Age	Position	Period
Cornew, Kenneth W.	49	Senior Executive Vice President and Chief Commercial Officer, Exelon;	2013 - Present
		President and CEO, Generation	2013 - Present
		Executive Vice President and Chief Commercial Officer, Exelon	2012 - 2013
		President and Chief Executive Officer, Constellation	2012 - 2013
		Senior Vice President, Exelon; President, Power Team	2008 - 2012
Nigro, Joseph	50	Executive Vice President, Exelon; Chief Executive Officer, Constellation	2013 - Present
		Senior Vice President, Portfolio Management and Strategy	2012 - 2013
		Vice President, Structuring and Portfolio Management, Exelon Power Team	2010 - 2012
Pacilio, Michael J.	54	Executive Vice President and Chief Operating Officer, Exelon Generation	2015 - Present
		President, Exelon Nuclear; Senior Vice President and Chief Nuclear Officer, Generation	2010 - 2015
		Chief Operating Officer, Exelon Nuclear	2007 - 2010
Hanson, Bryan C.	49	President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon Generation	2015 - Present
		Chief Operating Officer, Exelon Nuclear	2014 - 2015
		Senior Vice President of Operations, Generation	2010 - 2013
		Vice President of Operations, Generation	2009 - 2010
DeGregorio, Ronald	52	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.	48	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
Aiken, Robert	48	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

ComEd


Name	Age	Position	Period
Pramaggiore, Anne R.	56	Chief Executive Officer, ComEd	2012 - Present
		President, ComEd	2009 - Present
		Chief Operating Officer, ComEd	2009 - 2012
Donnelly, Terence R.	54	Executive Vice President and Chief Operating Officer, ComEd	2012 - Present
		Executive Vice President, Operations, ComEd	2009 - 2012
Trpik Jr., Joseph R.	45	Senior Vice President, Chief Financial Officer and Treasurer, ComEd	2009 - Present
Jensen, Val	59	Senior Vice President, Customer Operations, ComEd	2012 - Present
		Vice President, Marketing and Environmental Programs, ComEd	2008 - 2012
O’Neill, Thomas S.	52	Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd	2010 - Present
		Senior Vice President, Exelon	2009 - 2010
Marquez Jr., Fidel	53	Senior Vice President, Governmental and External Affairs, ComEd	2012 - Present
		Senior Vice President, Customer Operations, ComEd	2009 - 2012
Brookins, Kevin B.	53	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
Anthony, J. Tyler	50	Senior Vice President, Distribution Operations, ComEd	2010 - Present
		Vice President, Transmission and Substations, ComEd	2007 - 2010
Kozel, Gerald J.	42	Vice President, Controller, ComEd	2013 - Present
		Assistant Corporate Controller, Exelon	2012 - 2013
		Director of Financial Reporting and Analysis, Exelon	2009 - 2012

PECO


Name	Age	Position	Period
Adams, Craig L.	62	President and Chief Executive Officer, PECO	2012 - Present
		Senior Vice President and Chief Operating Officer, PECO	2007 - 2012
Barnett, Phillip S.	51	Senior Vice President and Chief Financial Officer, PECO	2007 - Present
		Treasurer, PECO	2012 - Present
Innocenzo, Michael A.	49	Senior Vice President and Chief Operations Officer, PECO	2012 - Present
		Vice President, Distribution System Operations and Smart Grid/Smart Meter, PECO	2010 - 2012
		Vice President, Distribution System Operations	2007 - 2010


Name	Age	Position	Period
Webster Jr., Richard G.	53	Vice President, Regulatory Policy and Strategy, PECO	2012 - Present
		Director of Rates and Regulatory Affairs	2007 - 2012
Murphy, Elizabeth A.	55	Vice President, Governmental and External Affairs, PECO	2012 - Present
		Director, Governmental & External Affairs, PECO	2007 - 2012
Jiruska, Frank J.	54	Vice President, Customer Operations, PECO	2013 - Present
		Director of Energy and Marketing Services, PECO	2010 - 2013
Diaz Jr., Romulo L.	68	Vice President and General Counsel, PECO	2012 - Present
		Vice President, Governmental and External Affairs, PECO	2009 - 2012
Bailey, Scott A.	38	Vice President and Controller, PECO	2012 - Present
		Assistant Controller, Generation	2011 - 2012
		Director of Accounting, Power Team	2007 - 2011

BGE


Name	Age	Position	Period
Butler, Calvin G.	45	Chief Executive Officer, BGE	2014 - Present
		Senior Vice President, Regulatory and External Affairs, BGE	2013 - 2014
		Senior Vice President, Corporate Affairs, Exelon	2011 - 2013
		Senior Vice President, Human Resources, Exelon	2010 - 2011
		Senior Vice President, Corporate Affairs, ComEd	2009 - 2010
Woerner, Stephen J.	47	President, BGE	2014 - Present
		Chief Operating Officer, BGE	2012 - Present
		Senior Vice President, BGE	2009 - 2014
		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
Vahos, David M.	42	Chief Financial Officer and Treasurer	2014 - Present
		Vice President and Controller, BGE	2012 - 2014
		Executive Director, Audit, Constellation	2010 - 2012
		Director, Finance, BGE	2006 - 2010
Case, Mark D.	53	Vice President, Strategy and Regulatory Affairs, BGE	2012 - Present
		Senior Vice President, Strategy and Regulatory Affairs, BGE	2007 - 2012
Biagiotti, Robert D.	45	Vice President, Customer Operations and Chief Customer Officer, BGE	2015 - Present
		Vice President, Gas Distribution, BGE	2011-2015
		Director, Gas and Electric Field Services, BGE	2008-2011


Name	Age	Position	Period
Gahagan, Daniel P.	61	Vice President and General Counsel, BGE	2007 - Present
Bauer, Matthew N.	38	Vice President and Controller, BGE	2014 - Present
		Vice President of Power Finance, Exelon Power	2012 - 2014
		Director, FP&A and Retail, Constellation	2012 - 2012
		Executive Director, Corporate Development, Constellation	2009 - 2012

(a)	Effective July 1, 2014, Jonathan W. Thayer’s title was changed from Executive Vice President and Chief Financial Officer, Exelon to Senior Executive Vice President and Chief Financial Officer, Exelon.

ITEM 1A.

RISK FACTORS

Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond that 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 finance and risk committee and audit committee of the Exelon board of directors and the ComEd, PECO and BGE boards of directors. In addition, the generation oversight committee of the Exelon board of directors evaluates risks related to the generation business. 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.

Exelon’s financial condition and results of operations are affected to a significant degree by: (1) Generation’s position as a predominantly nuclear generator selling power into competitive energy markets with a concentration in select regions, 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. Factors that affect the financial condition and results of operations of the Registrants fall primarily under the following categories, all of which are discussed in further detail below:

•

Market and Financial Factors. Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy 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 price of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, and (4) the impacts of on-going competition in the retail channel.

•

Regulatory and Legislative Factors. The regulatory and legislative factors that may affect the Registrants 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 affected by changes in the design of competitive wholesale power markets or Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including legislation or regulation regarding climate change and renewable portfolio standards, could have significant effects on the Registrants. Also, returns for ComEd, PECO and BGE are influenced significantly by state regulation and regulatory proceedings.

•

Operational Factors. The Registrants’ operational performance is subject to those factors 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 their customers and regulators, are affected by those companies’ ability to maintain the reliability and safety of their energy delivery systems.

•

Risks Related to the Pending Merger with PHI. There are various risks and uncertainties associated with the merger agreement announced with PHI on April 29, 2014.

A discussion of each of these risk categories and other risk factors is included below.

Market and Financial Factors

Generation is exposed to depressed prices in the wholesale and retail power markets, which may negatively affect its results of operations and cash flows. (Exelon and Generation)

Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore subject to variability as spot and forward market prices in the markets in which it operates rise and fall.

Price of Fuels: The 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. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit. Often, the next unit of electricity will be supplied from generating stations fueled by fossil fuels. Consequently, changes in the market price of fossil fuels often result in 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 downward pressure on natural gas prices and, therefore, on power prices. The continued addition of supply from new alternative generation resources, such as wind and solar, whether mandated through RPS or otherwise subsidized or encouraged through climate legislation or regulation, may displace a higher marginal cost plant, further reducing power prices. In addition, further delay or elimination of EPA air quality regulations could prolong the duration for which the cost of pollution from fossil fuel generation is not factored into market prices.

Demand and Supply: The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs can each depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on electricity market prices. The tepid economic environment in recent years and growing energy efficiency and demand response initiatives have limited the demand for electricity in Generation’s markets. In addition, in some markets, the supply of electricity through wind or solar generation, when combined with other base-load generation such as nuclear, may often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants. The risk of increased supply in excess of demand is heightened by continued or increased RPS mandates or other subsidies, including ITCs and PTCs.

Retail Competition: Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and

wholesale generators (including Generation) use their retail operations to hedge generation output. Increased or more aggressive competition can adversely affect overall gross margins and profitability in Generation’s retail operations.

Sustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s results of operations and cash flows, and such impacts could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s ability to fund other discretionary uses of cash such as growth projects or to pay dividends. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Exelon’s and Generation’s results of operations through increased depreciation rates, impairment charges and accelerated future decommissioning costs which may be offset in whole or in part by reduced operating and maintenance expenses. A slow recovery in market conditions 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 RTOs and ISOs, 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.

Market Designs. The wholesale markets remain evolving markets that vary from region to region and are still developing rules, practices and procedures. Changes in these market rules, problems with rule implementation, or 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.

The Registrants are potentially affected by emerging technologies that may over time affect or transform the energy industry, including technologies related to energy generation, distribution and consumption. (Exelon, Generation, ComEd, PECO and BGE)

Some of these technologies include, but are not limited to further shale gas development or sources, cost-effective renewable energy technologies, broad consumer adoption of electric vehicles and energy storage devices. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could make portions

of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could materially affect the Registrants’ results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Market performance and other factors may decrease the value of NDT funds and employee benefit plan assets and may increase the related employee benefit plan 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 Generation’s funding requirements to decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets will increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB 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 OPEB plans. If future increases in pension and other postretirement costs as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, 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 investments with the NDT funds and benefit plan assets, and are unable to manage the related benefit plan liabilities, 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. 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, 2014, approximately 29%, or $2.5 billion of the Registrants’ available credit facilities were with European banks, excluding the unsecured bridge facility to provide financing for the proposed PHI acquisition. The credit facilities include $8.5 billion in aggregate total commitments of which $7.3 billion was available as of December 31, 2014. There were no borrowings under the Registrants’ credit facilities as of December 31, 2014. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.

The strength and depth of competition in 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, 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 in general, or Generation in particular, has deteriorated. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation.

ComEd’s, PECO’s and BGE’s operating agreements with PJM and PECO’s and BGE’s natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and ComEd, 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 forms of letters of credit or cash, which may have a material

adverse effect upon their liquidity. Collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO and BGE, with respect to their natural gas supply 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 ComEd, PECO and 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 “ring-fencing”) 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 ring-fencing 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 and cash flows 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 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 power markets. 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 that may significantly change the tax rules applicable to U.S. domiciled corporations. Exelon cannot assess what the overall effect of such potential legislation might 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 its like-kind exchange transaction. Exelon and the IRS failed to reach a settlement on the like-kind exchange position and Exelon filed a petition on December 31, 2013 to initiate litigation in the United States Tax Court. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the like-kind exchange position. The litigation could take three to five years including appeals, if necessary.

As of December 31, 2014, 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 $810 million, of which approximately $310 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 $90 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 14—Income Taxes 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—Significant Accounting Policies and Note 14—Income Taxes 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 a return 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 and potentially additional uncollectible accounts expense for ComEd, PECO and BGE. In addition, any challenges by the regulators or ComEd, PECO and BGE as to the recoverability of these costs could have a material effect on the Registrants’ results of operations and cash flows. 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 increased 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 60%, 51%, 62%, 68% and 77% of total assets for Exelon, Generation, ComEd, PECO and BGE, respectively, as of December 31, 2014. In addition, Exelon and Generation have significant balances related to unamortized energy contracts. See Note 4—Mergers, Acquisitions, and Dispositions and Note 10—Intangible Assets 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 holds investments in coal-fired plants in Georgia that are subject to long-term leases. The investments are accounted for as direct financing lease investments. The investments represent the estimated residual value of the leased assets at the end of the lease term. On an annual basis, Exelon reviews the estimated residual values of its direct financing lease investments and records a non-cash impairment charge to expense if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. Such an impairment could have a material adverse impact on Exelon’s results of operations.

Exelon and ComEd had approximately $2.7 billion of goodwill recorded at December 31, 2014 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 to expense, which will also reduce 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 Note 7—Property, Plant and Equipment, Note 8—Impairment of Long Lived Assets and Note 10—Intangible Assets 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 electric generating facilities 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 of electric or gas systems or infrastructure 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 affected 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 became 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.

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 Factors

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 need to 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. Similarly, final regulations under Section 111(d) of the Clean Air Act may not provide sufficient incentives for states to utilize carbon-free nuclear power as a means of meeting greenhouse gas emission reduction requirements, while continuing a policy of favoring renewable energy sources. 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 subsequently dismissed New Jersey Capacity Legislation and the MDPSC’s RFP for new gas-fired generation in Maryland. See Note 3—Regulatory Matters 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. As of December 31, 2014, Generation has submitted its triennial application seeking reauthorization to sell at market-based rates in the Southeast region. Generation’s previous submission seeking reauthorization to sell at market-based rates was accepted by FERC on August 5, 2014 for the Northeast region (including PJM).

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that applies to Exelon is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires the creation of a new regulatory regime for over-the-counter swaps (Swaps), including mandatory clearing for certain categories of Swaps, incentives to shift Swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. For non security-based Swaps including commodity Swaps, Dodd-Frank empowers the Commodity Futures Trading Commission (CFTC) to promulgate regulations implementing the law’s objectives. The primary aim of Dodd-Frank is to regulate the key intermediaries in the Swaps market, which entities are either swap dealers (SDs), major swap participants (MSPs), and certain other financial entities, but the law also applies to a lesser

degree to end-users of Swaps. On January 12, 2015, President Obama signed into law a bill that exempts from margin requirements Swaps used by end-users to hedge or mitigate commercial risk. Moreover, the CFTC’s Dodd-Frank regulations preserve the ability of end users in the energy industry to hedge their risks using Swaps without being subject to mandatory clearing, and excepts or exempts end-users from many of the other substantive regulations. Accordingly, as an end-user, Generation is conducting its commercial business in a manner that does not require registration with the CFTC as an SD or MSP. Generation does not anticipate transacting in the future in a manner in which it would become a SD or MSP.

There are, however, some rulemakings that have not yet been finalized, including the capital and margin rules for (non-cleared) Swaps. Generation does not expect these rules to directly impact its collateral requirements. However, depending on the substance of these final rules in addition to certain international regulatory requirements still under development and that are similar to Dodd-Frank, Generation’s Swap counterparties could be subject to additional and potentially significant capitalization requirements. These regulations could motivate the SDs and MSPs to increase collateral requirements or cash postings from their counterparties, including Generation.

Generation continues to monitor the rulemaking proceedings with respect to the capital and margin rules, but cannot predict to what extent, if any, further refinements to Dodd-Frank requirements may impact its cash flows or financial position, but such impacts could be material.

ComEd, PECO and BGE could also be subject to some Dodd-Frank requirements to the extent they were to enter into Swaps. However, at this time, management of ComEd, PECO and BGE continue to expect that their companies will not be materially affected by Dodd-Frank.

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 and transactions incurred by ComEd, PECO, or BGE, with Generation, irrespective 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 is unable, or 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 22—Commitments and Contingencies 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, bad debt, 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—Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding rate proceedings.

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 Generation, 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, 2014, 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 would be 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 charge 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, 2014, the gain (loss) could have been as much as $(2.6) billion, $811 million and $480 million (before taxes) as a result of the elimination of ComEd’s, PECO’s and BGE’s regulatory assets and liabilities, respectively.

Further, Exelon would record a charge against OCI (before taxes) of up to $2.6 billion and $663 million for ComEd and BGE, respectively, related to Exelon’s net regulatory assets associated with its defined benefit postretirement plans. Exelon also has a net regulatory liability of $53 million (before taxes) associated with PECO’s defined benefit postretirement plans that would result in an increase in OCI if reversed. 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 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—Significant Accounting Policies, 3—Regulatory Matters and 10—Intangible Assets 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. 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 22—Commitments and Contingencies 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.

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. Following a remand from the U.S. Court of Appeals for the Seventh Circuit, FERC reaffirmed its decision related to allocation of new facilities 500 kV and above. The U.S. Court of Appeals for the Seventh Circuit remanded this decision a second time. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the issue of the cost allocation for facilities 500 kV and above. This FERC order only applies to facilities included in the PJM RTEP prior to February 1, 2013. For facilities subsequently approved, the costs of new facilities that are double circuit 345 kV or greater than or equal to 500 kV will be allocated 50% across the entire PJM footprint and 50% allocated to identified beneficiaries. Costs for all other facilities will be allocated to all identified beneficiaries. This later decision is subject to rehearing by FERC and possible appeal.

See Note 3—Regulatory Matters and Note 22—Commitments and Contingencies 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 22—Commitments and Contingencies 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.

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 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. On September 19, 2014, the NRC issued a revised rule codifying the NRC’s generic determinations regarding the environmental impacts of continued storage of spent nuclear fuel beyond a reactor’s licensed operating life. The Continued Storage Rule became effective on October 20, 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. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE a fee per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the United States Court of Appeals for the District of Columbia Circuit ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On January 3, 2014, the DOE filed a petition for rehearing which was denied by the D.C. Circuit Court on March 18, 2014. Also, on January 3, 2014, the DOE submitted a proposal to Congress to reduce the current SNF disposal fee to zero. On May 9, 2014, the DOE notified Generation that the SNF disposal fee was set to zero, effective May 16, 2014. Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. 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 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the spent nuclear fuel obligation. Generation cannot predict what, if any, fee will be established in the future for SNF disposal. However, such a fee could be material to Generation’s results of operations and cash flows.

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.

Operational Factors

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 power plants and ComEd’s, PECO’s and BGE’s distribution and transmission infrastructures could be affected 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. An example of such an event was the February 5, 2014 ice storm, which interrupted electric service delivery to customers in PECO’s service territory and resulted in significant restoration costs.

Another example of such an event includes 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. Natural disasters and other significant 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 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. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.

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 for generating units, particularly capacity factors for nuclear generating units, 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 $13.6 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 has made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all. See Note 22—Commitments and Contingencies 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, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units 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—Regulatory Matters 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 units, 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. Additionally, if the pledged assets are not sufficient to fund the Zion station decommissioning activities under the Asset Sale Agreement (ASA), Generation may have to seek remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 15—Asset Retirement Obligations 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, 2015, and the license for the Muddy Run Pumped Storage Project expires on September 1, 2015. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new 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. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding proceedings related to storm-related outages in ComEd’s service territory.

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 physical assets or information systems of the Registrants, their competitors, RTOs and ISOs, or regulators 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 in the Registrants or others in the industry 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 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 continues to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. Generation is pursuing investment opportunities in renewables, development of natural gas generation, distributed generation, potential expansion of the existing natural gas and oil Upstream and wholesale gas businesses, and entry into liquefied natural gas. 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 their regulatory-mandated Smart Grid initiatives. 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 Pending Merger with PHI

Exelon and PHI may encounter difficulties in satisfying the conditions for the completion of the Merger and the Merger may not be completed within the expected time frame or at all.

Consummation of the Merger is subject to the satisfaction or waiver of specified closing conditions, including (1) the approval of the Merger by the holders of a majority of the outstanding shares of the PHI common stock, (2) the receipt of regulatory approvals required to consummate the Merger, (3) the expiration or termination of the applicable waiting period under the HSR Act and (4) other customary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materiality qualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement. In addition, the obligation of Exelon to consummate the Merger is subject to the required regulatory approvals not, individually or in the aggregate, imposing terms, conditions, obligations or commitments that constitute a burdensome condition (as defined in the Merger Agreement).

In addition, conditions to the completion of the Merger may fail to be satisfied. Exelon or PHI may terminate the Merger Agreement if the Merger is not completed by July 29, 2015 except that, under certain circumstances, the date may be extended by Exelon or PHI to October 29, 2015. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information regarding the status of the merger.

The Merger is subject to the receipt of consent or approval from governmental entities that could delay the completion of the Merger or impose conditions that could have a material adverse effect on the combined company or that could cause abandonment of the Merger.

Completion of the Merger is conditioned upon the receipt of consents, orders, approvals or clearances, to the extent required, from the FERC, the FCC, the District of Columbia Public Service Commission, and the public utility commissions or similar entities in certain states in which the companies operate, including the Delaware Public Service Commission, MDPSC, the New Jersey Board of Public Utilities and the Virginia Department of Public Utilities. The Merger is also subject to

review by the DOJ Antitrust Division, under the HSR Act, and the expiration or earlier termination of the waiting period (and any extension of the waiting period) applicable to the Merger is a condition to closing the Merger. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information regarding the status of regulatory approvals.

Exelon and PHI have proposed conditions for approval in some of the regulatory filings that have been made and may subsequently propose or agree to further conditions, even if such conditions could have an adverse effect on Exelon, PHI or the combined company.

Exelon cannot provide assurance that all required regulatory consents or approvals will be obtained or that these consents or approvals will not contain terms, conditions or restrictions that would be detrimental to the combined company after the completion of the Merger. The Merger Agreement generally permits Exelon to terminate the Merger Agreement if the final terms of any of the required regulatory consents or approvals include burdensome conditions (as defined in the Merger Agreement). Any substantial delay in obtaining satisfactory approvals or the imposition of any terms or conditions in connection with such approvals could cause a material reduction in the expected benefits of the Merger.

Failure to obtain regulatory approval may result in Exelon’s payment of a reverse termination fee.

If the Merger Agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals, the failure to obtain regulatory approvals without burdensome conditions, or the breach by Exelon of its obligations in respect of obtaining regulatory approvals, Exelon will be required to pay PHI a reverse termination fee of up to $180 million, which would occur by means of PHI’s election to redeem the outstanding nonvoting preferred securities purchased by Exelon in connection with the execution of the Merger Agreement for no consideration other than the nominal par value of the stock.

Failure to complete the Merger could negatively affect the share price and the future business and financial results of Exelon.

Completion of the Merger is not assured and is subject to risks, including the risks that approval of the transaction by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If the Merger is not completed, the ongoing businesses of Exelon may be adversely affected and Exelon will be subject to several risks, including:

•

having to pay certain significant costs relating to the Merger without receiving the benefits of the Merger, including, in certain circumstances, a termination fee of up to $180 million payable by Exelon to PHI under certain circumstances; and

•

the share price of Exelon may decline if and to the extent that the current market prices reflect an assumption by the market that the Merger will be completed.

Exelon and PHI have incurred and will incur significant transaction and Merger-related costs in connection with the Merger.

Exelon and PHI have incurred and expect to incur additional non-recurring costs associated with combining the operations of the two companies. Most of these costs will be transaction costs, including fees paid to financial and legal advisors related to the Merger and related financing arrangements, and employment-related costs, including change-in- control related payments made to certain PHI executives. In addition, if the closing of the Merger is materially delayed, Exelon may be required to pay financing costs without having realized any benefits from the Merger during the period of delay.

Exelon will also incur transaction fees and costs related to formulating integration plans. Additional unanticipated costs may be incurred in the integration of the two companies’ businesses. Although Exelon expects that the elimination of costs, as well as the realization of other efficiencies related to the integration of the businesses, will exceed incremental transaction and Merger-related costs over time, this net benefit may not be achieved in the near term, or at all.

Exelon may not realize the expected benefits of the Merger because of integration difficulties and other challenges.

The success of the PHI acquisition will depend, in part, on Exelon’s ability to realize all or some of the anticipated benefits from integrating PHI’s business with Exelon’s existing businesses. The integration process may be complex, costly and time-consuming. The challenges associated with integrating the operations of PHI’s business include, among others:

•

delay in implementation of our business plan for the combined business;

•

unanticipated issues or costs in integrating financial, information technology, communications and other systems;

•

possible inconsistencies in standards, controls, procedures and policies, and compensation structures between PHI’ s structure and our structure;

•

unanticipated changes in applicable laws and regulations;

•

difficulties in retention of key employees;

•

operating risks inherent in PHI’s business and our business; and

•

unexpected regulatory requirements.

Exelon and PHI will be subject to various uncertainties while the Merger is pending that may adversely affect their ability to attract and retain key employees, and potentially affect the company’s financial results.

Uncertainty about the effect of the Merger on employees, suppliers and customers may have an adverse effect on Exelon and/or PHI. These uncertainties may impair Exelon’s and/or PHI’s ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, as employees and prospective employees may experience uncertainty about their future roles with the combined company. In addition, current and prospective Exelon and PHI employees may determine that they do not desire to work for the combined company for a variety of possible reasons.

The Merger may divert attention of management at Exelon and PHI, which could detract from efforts to meet business goals.

The pursuit of the Merger and the preparation for the integration may place a burden on management and internal resources. Any significant diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect Exelon’s and/or PHI’s financial results. The process of integrating the operations of PHI may require a disproportionate amount of resources and management attention. Exelon’s future operations and cash flows will depend to a significant degree upon Exelon’s ability to operate PHI efficiently, achieve the strategic operating objectives for the business and realize cost savings and synergies. Exelon’s management team may encounter unforeseen difficulties in managing the integration. In order to successfully integrate PHI, Exelon’s management team will need to focus on realizing anticipated synergies and cost savings on a timely basis while maintaining the efficiency of operations. Any substantial diversion of management attention could affect Exelon’s ability to achieve operational, financial and strategic objectives.

We are obligated to complete the Merger whether or not we have obtained the required financing.

Exelon intends to fund the cash consideration in the Merger using a combination of approximately $3.5 billion of debt, up to $1.0 billion in cash from asset sales, and the remainder through issuance of equity (including mandatory convertible securities). See Note 4—Mergers, Acquisitions, and Dispositions and Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding the merger financing.

The combined company’s assets, liabilities or results of operations could be adversely affected by unknown or unexpected events, conditions or actions that might occur at PHI prior to the closing of the Merger.

The PHI assets, liabilities, business, financial condition, cash flows, operating results and prospects to be acquired or assumed by Exelon by reason of the merger could be adversely affected before or after the Merger closing as a result of previously unknown events or conditions occurring or existing before the Merger closing. Adverse changes in PHI’s business or operations could occur or arise as a result of actions by PHI, legal or regulatory developments including the emergence or unfavorable resolution of pre-acquisition loss contingencies, deteriorating general business, market, industry or economic conditions, and other factors both within and beyond the control of PHI. A significant decline in the value of PHI assets to be acquired by Exelon or a significant increase in PHI liabilities to be assumed by Exelon could adversely affect the combined company’s future business, financial condition, cash flows, operating results and prospects.

Exelon may record goodwill that could become impaired and adversely affect its operating results.

In accordance with GAAP, the Merger will be accounted for as an acquisition of PHI common stock by Exelon and will follow the acquisition method of accounting for business combinations. The assets and liabilities of PHI will be consolidated with those of Exelon. The excess of the purchase price over the fair values of PHI’s assets and liabilities, if any, will be recorded as goodwill.

The amount of goodwill, which could be material, will be allocated to the appropriate reporting units of the combined company. Exelon is required to assess goodwill for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reporting units. To the extent the carrying value of any of those reporting units is greater than the fair value, a second step comparing the implied fair value of goodwill to the carrying amount would be required to determine if the goodwill is impaired. Such a potential impairment could result in a material non-cash charge that would have a material impact on Exelon’s future operating results and consolidated balance sheet.

Legal proceedings in connection with the Merger, the outcomes of which are uncertain, could delay or prevent the completion of the Merger.

One of the conditions to the closing of the Merger is that no judgment (whether preliminary, temporary or permanent) or other order by any court or other governmental entity shall be in effect that restrains, enjoins or otherwise prohibits or makes illegal the consummation of the Merger.

PHI and its directors have been named as defendants in purported class action lawsuits filed on behalf of named plaintiffs and other public stockholders challenging the proposed Merger and seeking, among other things, to enjoin the defendants from consummating the Merger on the agreed-upon terms. Exelon has been named as a defendant in these lawsuits. Exelon has also been named in a federal court case with similar claims. In September 2014, the parties reached a proposed settlement which is subject to court approval. Final court approval of the proposed settlement is not expected to occur until the second quarter of 2015, at the earliest.

If a plaintiff in these or any other litigation claims that may be filed in the future is successful in obtaining an injunction prohibiting the parties from completing the Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Merger in the expected time frame or altogether. If completion of the Merger is prevented or delayed, it could result in substantial costs to Exelon. In addition, Exelon could incur significant costs in connection with the lawsuits, including costs associated with the indemnification of PHI’s directors and officers.

Private parties who may believe they are adversely affected by the Merger and individual states may bring legal actions under the antitrust laws in certain circumstances or intervene in regulatory proceedings. Although Exelon and PHI believe the completion of the Merger will not conflict with any antitrust law, there can be no assurance that a challenge to the Merger on antitrust grounds will not be made or, if a challenge is made, what the result will be. Under the Merger Agreement, Exelon and PHI have agreed to use their reasonable best efforts to obtain all regulatory clearances necessary to complete the Merger as promptly as practicable. In addition, in order to complete the Merger, Exelon and PHI may be required to comply with conditions, terms, obligations or restrictions imposed by regulatory agencies and any such conditions, terms, obligations or restrictions may have the effect of delaying completion of the Merger, imposing additional material costs on or materially limiting Exelon’s revenues after the completion of the Merger, or otherwise reducing the anticipated benefits from the Merger. In addition, any such conditions, terms, obligations or restrictions could result in the delay or abandonment of the Merger.

The Merger may be completed on terms different from those contained in the Merger Agreement.

Prior to the completion of the Merger, Exelon and PHI may, by their mutual agreement, amend or alter the terms of the Merger Agreement, including with respect to, among other things, the Merger consideration to be received by PHI stockholders or any covenants or agreements with respect to the parties’ respective operations pending completion of the Merger. In addition, Exelon may choose to waive requirements of the Merger Agreement, including some conditions to closing of the Merger. Any such amendments, alterations or waivers may have negative consequences to Exelon.

Risks Related to the Merger with Constellation

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, 2014:

Station ^(a)

Region

Location

No. of

Units

Percent
Owned ^(b)

Primary
Fuel Type

Primary
Dispatch
Type ^(c)

Net
Generation
Capacity (MW) ^(d)

Limerick

Mid-Atlantic

Sanatoga, PA

Uranium

Base-load

2,317

Peach Bottom

Mid-Atlantic

Delta, PA

Uranium

Base-load

1,165

^(f)

Salem

Mid-Atlantic

Lower Alloways Creek
Township, NJ

42.59

Uranium

Base-load

1,005

^(f)

Calvert Cliffs

Mid-Atlantic

Lusby, MD

50.01

Uranium

Base-load

878

^(f)(g)

Three Mile Island

Mid-Atlantic

Middletown, PA

Uranium

Base-load

837

Oyster Creek

Mid-Atlantic

Forked River, NJ

Uranium

Base-load

625

^(e)

Conowingo

Mid-Atlantic

Darlington, MD

Hydroelectric

Base-load

572

Criterion

Mid-Atlantic

Oakland, MD

Wind

Base-load

Fourmile

Mid-Atlantic

Garrett County, MD

Wind

Base-load

Solar Horizons

Mid-Atlantic

Emmitsburg, MD

Solar

Base-load

Solar New Jersey 2

Mid-Atlantic

Various, NJ

Solar

Base-load

Solar New Jersey 1

Mid-Atlantic

Various, NJ

Solar

Base-load

Solar Maryland

Mid-Atlantic

Various, MD

Solar

Base-load

Solar Federal

Mid-Atlantic

Trenton, NJ

Solar

Base-load

Solar Maryland 2

Mid-Atlantic

Pocomoke, MD

Solar

Base-load

Solar New Jersey 3

Mid-Atlantic

Middle Township, NJ

Solar

Base-load

Muddy Run

Mid-Atlantic

Drumore, PA

Hydroelectric

Intermediate

1,070

Eddystone 3, 4

Mid-Atlantic

Eddystone, PA

Oil/Gas

Intermediate

760

Croydon

Mid-Atlantic

West Bristol, PA

Oil

Peaking

391

Perryman

Mid-Atlantic

Belcamp, MD

Oil/Gas

Peaking

353

Handsome Lake

Mid-Atlantic

Kennerdell, PA

Gas

Peaking

268

Riverside

Mid-Atlantic

Baltimore, MD

Oil/Gas

Peaking

113

^(h)

Westport

Mid-Atlantic

Baltimore, MD

Gas

Peaking

115

Notch Cliff

Mid-Atlantic

Baltimore, MD

Gas

Peaking

118

Richmond

Mid-Atlantic

Philadelphia, PA

Oil

Peaking

Gould Street

Mid-Atlantic

Baltimore, MD

Gas

Peaking

Philadelphia Road

Mid-Atlantic

Baltimore, MD

Oil

Peaking

Eddystone

Mid-Atlantic

Eddystone, PA

Oil

Peaking

Fairless Hills

Mid-Atlantic

Fairless Hills, PA

Landfill Gas

Peaking

Delaware

Mid-Atlantic

Philadelphia, PA

Oil

Peaking

Southwark

Mid-Atlantic

Philadelphia, PA

Oil

Peaking

Falls

Mid-Atlantic

Morrisville, PA

Oil

Peaking

Moser

Mid-Atlantic

Lower PottsgroveTwp., PA

Oil

Peaking

Chester

Mid-Atlantic

Chester, PA

Oil

Peaking

Schuylkill

Mid-Atlantic

Philadelphia, PA

Oil

Peaking

Salem

Mid-Atlantic

Lower Alloways Creek Twp, NJ

42.59

Oil

Peaking

^(f)

Pennsbury

Mid-Atlantic

Morrisville, PA

Landfill Gas

Peaking

Total Mid-Atlantic

11,420

Braidwood

Midwest

Braidwood, IL

Uranium

Base-load

2,378

LaSalle

Midwest

Seneca, IL

Uranium

Base-load

2,327

Byron

Midwest

Byron, IL

Uranium

Base-load

2,344

Dresden

Midwest

Morris, IL

Uranium

Base-load

1,845

Quad Cities

Midwest

Cordova, IL

Uranium

Base-load

1,403

^(f)

Clinton

Midwest

Clinton, IL

Uranium

Base-load

1,069

Michigan Wind 2

Midwest

Sanilac Co., MI

Wind

Base-load

Station ^(a)

Region

Location

No. of

Units

Percent
Owned ^(b)

Primary
Fuel Type

Primary
Dispatch
Type ^(c)

Net
Generation
Capacity (MW) ^(d)

Beebe

Midwest

Gratiot Co., MI

Wind

Base-load

Michigan Wind 1

Midwest

Huron Co., MI

Wind

Base-load

Harvest 2

Midwest

Huron Co., MI

Wind

Base-load

Harvest

Midwest

Huron Co., MI

Wind

Base-load

Beebe 1B

Midwest

Gratiot Co., MI

Wind

Base-load

Ewington

Midwest

Jackson Co., MN

Wind

Base-load

^(f)

Marshall

Midwest

Lyon Co., MN

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)

Wolf

Midwest

Nobles Co., MN

Wind

Base-load

^(f)

CP Windfarm

Midwest

Faribault Co., MN

Wind

Base-load

Blue Breezes

Midwest

Faribault Co., MN

Wind

Base-load

Cowell

Midwest

Pipestone Co., MN

Wind

Base-load

^(f)

Solar Ohio

Midwest

Toledo, OH

Solar

Base-load

Southeast Chicago

Midwest

Chicago, IL

Gas

Peaking

296

Total Midwest

12,153

Whitetail

ERCOT

Laredo, TX

Wind

Base-load

Wolf Hollow 1, 2, 3

ERCOT

Granbury, TX

Gas

Intermediate

704

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

⁽ⁱ⁾

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

4,003

Holyoke Solar

New England

Various, MA

Solar

Base-load

Solar Massachusetts

New England

Various, MA

Solar

Base-load

Solar Net Metering

New England

Uxbridge, MA

Solar

Base-load

Solar Connecticut

New England

Various, CT

Solar

Base-load

Mystic 8, 9

New England

Charlestown, MA

Gas

Intermediate

1,418

Mystic 7

New England

Charlestown, MA

Oil/Gas

Intermediate

575

Wyman

New England

Yarmouth, ME

5.9

Oil

Intermediate

^(f)

Medway

New England

West Medway, MA

Oil/Gas

Peaking

117

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

2,218

Solar New York

New York

Bethlehem, NY

Solar

Base-load

Nine Mile Point

New York

Scriba, NY

50.01

Uranium

Base-load

835

^(f)(g)

Ginna

New York

Ontario, NY

50.01

Uranium

Base-load

288

^(f)(g)

Total New York

1,125

AVSR

Other

Lancaster, CA

Solar

Base-load

242

Shooting Star

Other

Greensburg, KS

Wind

Base-load

104

Exelon Wind 4

Other

Gruver, TX

Wind

Base-load

Bluegrass Ridge

Other

King City, MO

Wind

Base-load

Conception

Other

Barnard, MO

Wind

Base-load

Cow Branch

Other

Rock Port, MO

Wind

Base-load

Mountain Home

Other

Glenns Ferry, ID

Wind

Base-load

High Mesa

Other

Elmore Co., ID

Wind

Base-load

Echo 1

Other

Echo, OR

Wind

Base-load

^(f)

Sacramento PV

Energy

Other

Sacremento, CA

Solar

Base-load

Cassia

Other

Buhl, ID

Wind

Base-load

Wildcat

Other

Lovington, NM

Wind

Base-load

Sunnyside

Other

Sunnyside, UT

Waste Coal

Base-load

^(f)

Echo 2

Other

Echo, OR

Wind

Base-load

Station ^(a)

Region

Location

No. of

Units

Percent
Owned ^(b)

Primary
Fuel Type

Primary
Dispatch
Type ^(c)

Net
Generation
Capacity (MW) ^(d)

Tuana Springs

Other

Hagerman, ID

Wind

Base-load

Greensburg

Other

Greensburg, KS

Wind

Base-load

Echo 3

Other

Echo, OR

Wind

Base-load

^(f)

Exelon Wind 1

Other

Gruver, TX

Wind

Base-load

Exelon Wind 2

Other

Gruver, TX

Wind

Base-load

Exelon Wind 3

Other

Gruver, TX

Wind

Base-load

Exelon Wind 5

Other

Texhoma, TX

Wind

Base-load

Exelon Wind 6

Other

Texhoma, TX

Wind

Base-load

Exelon Wind 7

Other

Sunray, TX

Wind

Base-load

Exelon Wind 8

Other

Sunray, TX

Wind

Base-load

Exelon Wind 9

Other

Sunray, TX

Wind

Base-load

Exelon Wind 10

Other

Dumas, TX

Wind

Base-load

Exelon Wind 11

Other

Dumas, TX

Wind

Base-load

High Plains

Other

Panhandle, TX

99.5

Wind

Base-load

^(f)

Three Mile Canyon

Other

Boardman, OR

Wind

Base-load

Solar Arizona

Other

Various, AZ

Solar

Base-load

Outback Solar

Other

Christmas Valley, OR

Solar

Base-load

Loess Hills

Other

Rock Port, MO

Wind

Base-load

Denver Airport Solar

Other

Denver, CO

Solar

Base-load

California PV Energy

Other

Various, CA

Solar

Base-load

Solar California

Other

Various, CA

Solar

Base-load

Solar Georgia

Other

Various, GA

Solar

Base-load

Hillabee

Other

Alexander City, AL

Gas

Intermediate

695

Grande Prairie

Other

Alberta, Canada

Gas

Peaking

SEGS 4, 5, 6

Other

Boron, CA

4.2-12.2

Solar

Peaking

^(f)

Total Other

1,834

Total

32,753

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

(b)	100%, unless otherwise indicated.

(c)

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.

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

(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)

Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2. Generation also had a unit-contingent PPA with CENG under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under the pre-existing PPAs through 2014.

(h)	Generation has agreed to retire and cease generation operation at the Riverside 6 unit effective June 1, 2014.

(i)

As of December 31, 2014, the assets and liabilities of Quail Run are reported as Assets held for sale and within Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for further information.

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.

In addition to the electric generating stations, Generation has working interests in 9 natural gas and oil exploration and production properties (Upstream) across the United States. Production volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, weather events, price effects and other factors.

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—Exelon Generation Company, LLC. 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, 2014 were as follows:


Voltage (Volts)		Circuit Miles
765,000		90
345,000		2,656
138,000		2,306

ComEd’s electric distribution system includes 35,464 circuit miles of overhead lines and 30,778 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, 2014 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 12,989 circuit miles of overhead lines and 8,948 circuit miles of underground lines.

Gas

The following table sets forth PECO’s natural gas pipeline miles at December 31, 2014:


	Pipeline Miles
Transmission		30
Distribution		6,792
Service piping		6,128

Total		12,950

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, 2014 were as follows:


Voltage (Volts)		Circuit Miles
500,000		218
230,000		322
138,000		54
115,000		697

BGE’s electric distribution system includes 9,386 circuit miles of overhead lines and 16,148 circuit miles of underground lines.

Gas

The following table sets forth BGE’s natural gas pipeline miles at December 31, 2014:


	Pipeline Miles
Transmission		163
Distribution		7,114
Service piping		6,179

Total		13,456

BGE has an LNG facility located in Baltimore, Maryland that has a storage capacity of 1,055 mmcf and a send-out capacity of 332 mmcf/day, an LNG facility located in Westminster, Maryland that has a storage capacity of 6 mmcf and a send-out capacity of 6 mmcf/day, and a propane-air plant located in Baltimore, Maryland, with a storage capacity of 546 mmcf and a send-out capacity of 85 mmcf/day. In addition, BGE owns 12 natural gas city gate stations and 20 direct pipeline customer delivery points at various locations throughout its gas service territory.

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 Note 3—Regulatory Matters and Note 22—Commitments and Contingencies 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, 2015, there were 859,833,343 shares of common stock outstanding and approximately 123,997 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:


	2014								2013
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	38.93	$	36.26	$	37.73	$	33.94	$	30.59	$	32.42	$	37.80	$	34.56
Low price		33.07		30.66		33.11		26.45		26.64		29.42		29.84		29.10
Close		37.08		34.09		36.48		33.56		27.39		29.64		30.88		34.48
Dividends		0.310		0.310		0.310		0.310		0.310		0.310		0.310		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 2010 through 2014.

This performance chart assumes:

•

$100 invested on December 31, 2009 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and

•

All dividends are reinvested.

LOGO


	Value of Investment at December 31,
	2009	2010	2011	2012	2013	2014
Exelon Corporation	$100	$74.88	$77.99	$53.48	$49.25	$66.68
S&P 500	$100	$139.23	$139.23	$157.89	$204.63	$227.94
S&P Utilities	$100	$107.71	$123.69	$120.09	$130.60	$162.33

Generation

As of January 31, 2015, Exelon indirectly held the entire membership interest in Generation.

ComEd

As of January 31, 2015, there were 127,016,950 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, 2015, in addition to Exelon, there were 297 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

PECO

As of January 31, 2015, 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, 2015, 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 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, in connection with the Constellation merger, BGE was 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 and notify the MDPSC that BGE’s equity ratio is at least 48% within five business days after dividend payment. 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, 2014, Exelon had retained earnings of $10,910 million, including Generation’s undistributed earnings of $3,803 million, ComEd’s retained earnings of $851 million consisting of retained earnings appropriated for future dividends of $2,490 million, partially offset by $(1,639) million of unappropriated retained deficits, PECO’s retained earnings of $681 million, and BGE’s retained earnings of $1,203 million.

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2014 and 2013:


	2014								2013
(per share)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter
Exelon	$	0.310	$	0.310	$	0.310	$	0.310	$	0.310	$	0.310	$	0.310	$	0.525

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


	2014								2013
(in millions)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter
Generation	$	205	$	205	$	205	$	30	$	75	$	76	$	263	$	211
ComEd		77		77		77		76		55		55		55		55
PECO		80		80		80		80		83		83		83		83

First Quarter 2015 Dividend. On January 27, 2015, the Exelon Board of Directors declared a first quarter 2015 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on March 10, 2015, to shareholders of record of Exelon at the end of the day on February 13, 2015.

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)	2014 ^(a)		2013		2012 ^(b)		2011		2010
Statement of Operations data:
Operating revenues	$	27,429	$	24,888	$	23,489	$	19,063	$	18,644
Operating income		3,096		3,669		2,373		4,479		4,726
Income from continuing operations		1,820		1,729		1,171		2,499		2,563
Net income		1,820		1,729		1,171		2,499		2,563
Net income attributable to common shareholders		1,623		1,719		1,160		2,495		2,563
Earnings per average common share (diluted):
Income from continuing operations	$	1.88	$	2.00	$	1.42	$	3.75	$	3.87

Net income	$	1.88	$	2.00	$	1.42	$	3.75	$	3.87

Dividends per common share	$	1.24	$	1.46	$	2.10	$	2.10	$	2.10

Average shares of common stock outstanding—diluted		864		860		819		665		663

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis.

(b)	2012 financial results include the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012.


	December 31,
(In millions)	2014		2013		2012		2011		2010
Balance Sheet data:
Current assets	$	12,097	$	10,137	$	10,140	$	5,713	$	6,398
Property, plant and equipment, net		52,087		47,330		45,186		32,570		29,941
Noncurrent regulatory assets		6,076		5,910		6,497		4,518		4,140
Goodwill		2,672		2,625		2,625		2,625		2,625
Other deferred debits and other assets		13,882		13,922		14,113		9,569		9,136

Total assets	$	86,814	$	79,924	$	78,561	$	54,995	$	52,240

Current liabilities	$	8,762	$	7,728	$	7,791	$	5,134	$	4,240
Long-term debt, including long-term debt to financing trusts		20,010		18,271		18,346		12,189		12,004
Noncurrent regulatory liabilities		4,550		4,388		3,981		3,627		3,555
Other deferred credits and other liabilities		29,359		26,597		26,626		19,570		18,791
Preferred securities of subsidiary		—		—		87		87		87
Noncontrolling interest		1,332		15		106		3		3
BGE preference stock not subject to mandatory redemption		193		193		193		—		—
Shareholders’ equity		22,608		22,732		21,431		14,385		13,560

Total liabilities and shareholders’ equity	$	86,814	$	79,924	$	78,561	$	54,995	$	52,240

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)	2014 ^(a)		2013		2012 ^(b)		2011		2010
Statement of Operations data:
Operating revenues	$	17,393	$	15,630	$	14,437	$	10,447	$	10,025
Operating income		1,176		1,677		1,113		2,875		3,046
Net income		1,019		1,060		558		1,771		1,972
Net income attributable to membership interest		835		1,070		562		1,771		1,972

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis.

(b)	2012 financial results include the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012.


	December 31,
(In millions)	2014		2013		2012		2011		2010
Balance Sheet data:
Current assets	$	7,638	$	6,439	$	6,211	$	3,217	$	3,087
Property, plant and equipment, net		22,945		20,111		19,531		13,475		11,662
Other deferred debits and other assets		14,765		14,682		14,939		10,741		9,785

Total assets	$	45,348	$	41,232	$	40,681	$	27,433	$	24,534

Current liabilities	$	4,459	$	3,867	$	4,097	$	2,144	$	1,843
Long-term debt		7,652		7,168		7,455		3,674		3,676
Other deferred credits and other liabilities		19,186		17,455		16,464		12,907		11,838
Noncontrolling interest		1,333		17		108		5		5
Member’s equity		12,718		12,725		12,557		8,703		7,172

Total liabilities and member’s equity	$	45,348	$	41,232	$	40,681	$	27,433	$	24,534

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)	2014		2013		2012		2011		2010
Statement of Operations data:
Operating revenues	$	4,564	$	4,464	$	5,443	$	6,056	$	6,204
Operating income		980		954		886		982		1,056
Net income		408		249		379		416		337


	December 31,
(In millions)	2014		2013		2012		2011		2010
Balance Sheet data:
Current assets	$	1,723	$	1,540	$	1,775	$	2,188	$	2,151
Property, plant and equipment, net		15,793		14,666		13,826		13,121		12,578
Goodwill		2,625		2,625		2,625		2,625		2,625
Noncurrent regulatory assets		852		933		666		699		947
Other deferred debits and other assets		4,399		4,354		4,013		4,005		3,351

Total assets	$	25,392	$	24,118	$	22,905	$	22,638	$	21,652

Current liabilities	$	1,986	$	2,048	$	1,655	$	2,071	$	2,134
Long-term debt, including long-term debt to financing trusts		5,904		5,264		5,521		5,421		4,860
Noncurrent regulatory liabilities		3,655		3,512		3,229		3,042		3,137
Other deferred credits and other liabilities		5,940		5,766		5,177		5,067		4,611
Shareholders’ equity		7,907		7,528		7,323		7,037		6,910

Total liabilities and shareholders’ equity	$	25,392	$	24,118	$	22,905	$	22,638	$	21,652

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)	2014		2013		2012		2011		2010
Statement of Operations data:
Operating revenues	$	3,094	$	3,100	$	3,186	$	3,720	$	5,519
Operating income		572		666		623		655		661
Net income		352		395		381		389		324
Net income attributable to common shareholder		352		388		377		385		320


	December 31,
(In millions)	2014		2013		2012		2011		2010
Balance Sheet data:
Current assets	$	714	$	906	$	1,094	$	1,243	$	1,670
Property, plant and equipment, net		6,801		6,384		6,078		5,874		5,620
Noncurrent regulatory assets		1,529		1,448		1,378		1,216		968
Other deferred debits and other assets		899		879		803		823		727

Total assets	$	9,943	$	9,617	$	9,353	$	9,156	$	8,985

Current liabilities	$	653	$	891	$	1,158	$	1,145	$	1,163
Long-term debt, including long-term debt to financing trusts		2,430		2,131		1,831		1,781		2,156
Noncurrent regulatory liabilities		657		629		538		585		418
Other deferred credits and other liabilities		3,082		2,901		2,757		2,620		2,278
Preferred securities		—		—		87		87		87
Shareholders’ equity		3,121		3,065		2,982		2,938		2,883

Total liabilities and shareholders’ equity	$	9,943	$	9,617	$	9,353	$	9,156	$	8,985

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)	2014		2013		2012			2011		2010
Statement of Operations data:
Operating revenues	$	3,165	$	3,065	$	2,735		$	3,068	$	3,541
Operating income		439		449		132			314		350
Net income		211		210		4			136		147
Net income (loss) attributable to common shareholder		198		197		(9	)		123		134


	December 31,
(In millions)	2014		2013		2012 ^(a)		2011 ^(a)		2010 ^(a)
Balance Sheet data:
Current assets	$	957	$	1,011	$	980	$	969	$	1,012
Property, plant and equipment, net		6,204		5,864		5,498		5,132		4,754
Noncurrent regulatory assets		510		524		522		551		566
Other deferred debits and other assets		407		462		506		551		545

Total assets	$	8,078	$	7,861	$	7,506	$	7,203	$	6,877

Current liabilities	$	846	$	827	$	980	$	734	$	728
Long-term debt, including long-term debt to financing trusts and variable interest entities		2,125		2,199		1,969		2,186		2,060
Noncurrent regulatory liabilities		200		204		214		201		192
Other deferred credits and other liabilities		2,154		2,076		1,985		1,781		1,634
Preference stock not subject to mandatory redemption		190		190		190		190		190
Shareholders’ equity		2,563		2,365		2,168		2,111		2,073

Total liabilities and shareholders’ equity	$	8,078	$	7,861	$	7,506	$	7,203	$	6,877

(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 the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services, and engages in natural gas and oil exploration and production activities (Upstream).

•

As a result of the Constellation merger, Generation owns a 50.01% interest in CENG. During 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation fully consolidated CENG’s financial position and results of operations into their businesses beginning on April 1, 2014.

•

ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services to retail customers 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 electricity 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 natural gas and the provision of electricity distribution and transmission and gas 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 24—Segment Information 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 the year ended December 31, 2014 compared to the same period in 2013. The 2014 financial results only include the operations of CENG on a fully consolidated basis from the date Generation assumed operational control, April 1, 2014, through December 31, 2014. All amounts presented below are before the impact of income taxes, except as noted.


	The Years Ended December 31,																					Favorable (Unfavorable) Variance
	2014																		2013
	Generation^(a)			ComEd			PECO			BGE			Other			Exelon			Exelon
Operating revenues	$	17,393		$	4,564		$	3,094		$	3,165		$	(787	)	$	27,429		$	24,888		$	2,541
Purchased power and fuel expense		9,925			1,177			1,261			1,417			(777	)		13,003			10,724			(2,279	)

Revenue net of purchased power and fuel expense ^(b)		7,468			3,387			1,833			1,748			(10	)		14,426			14,164			262

Other operating expenses
Operating and maintenance		5,566			1,429			866			717			(10	)		8,568			7,270			(1,298	)
Depreciation and amortization		967			687			236			371			53			2,314			2,153			(161	)
Taxes other than income		465			293			159			221			16			1,154			1,095			(59	)

Total other operating expenses		6,998			2,409			1,261			1,309			59			12,036			10,518			(1,518	)
Equity in (losses) earnings of unconsolidated affiliates		(20	)		—			—			—			—			(20	)		10			(30	)
Gain (loss) on sales of assets		437			2			—			—			(2	)		437			13			424
Gain on consolidation and acquisition of businesses		289			—			—			—			—			289			—			289

Operating income (loss)		1,176			980			572			439			(71	)		3,096			3,669			(573	)

Other income and (deductions)
Interest expense, net		(356	)		(321	)		(113	)		(106	)		(169	)		(1,065	)		(1,356	)		291
Other, net		406			17			7			18			7			455			460			(5	)

Total other income and (deductions)		50			(304	)		(106	)		(88	)		(162	)		(610	)		(896	)		286

Income (loss) before income taxes		1,226			676			466			351			(233	)		2,486			2,773			(287	)
Income taxes		207			268			114			140			(63	)		666			1,044			378

Net income (loss)		1,019			408			352			211			(170	)		1,820			1,729			91

Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		184			—			—			13			—			197			10			(187	)

Net income (loss) attributable to common shareholders	$	835		$	408		$	352		$	198		$	(170	)	$	1,623		$	1,719		$	(96	)

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis from April 1, 2014 through December 31, 2014.

(b)

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 attributable to common shareholders was $1,623 million for the year ended December 31, 2014 as compared to $1,719 million for the year ended December 31, 2013, and diluted earnings per average common share were $1.88 for the year ended December 31, 2014 as compared to $2.00 for the year ended December 31, 2013.

Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $262 million as compared to 2013. The year-over-year increase reflects the inclusion of CENG’s results beginning April 1, 2014 and was primarily due to the following favorable factors:

•

Increase of $815 million at Generation primarily due to the inclusion of CENG’s results beginning April 1, 2014 through December 31, 2014, a decrease in fuel costs related to the cancellation of DOE spent nuclear fuel disposal fees, increased capacity prices related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, and favorable portfolio management activities in the New England and South regions; partially offset by higher procurement costs for replacement power related to the extreme cold weather in the first quarter of 2014 and lower realized energy prices related to executing Generation’s ratable hedging strategy;

•

Increase of $365 million at Generation related to the reduction in amortization of in-the-money energy contracts recorded at fair value at the Constellation merger date and an increase related to the amortization of out-of-the money energy contracts recorded at fair value upon the consolidation of CENG;

•

Increase of $30 million at ComEd primarily reflecting higher transmission revenue due to increased capital investment and an increase of $93 million as a result of increased cost recovery associated with energy efficiency programs and uncollectible accounts expense (both offset below in operating and maintenance expense);

•

Increase of $33 million at PECO primarily due to increased recovery from regulatory programs (offset below primarily in operating and maintenance expense); and

•

Increase of $104 million at BGE primarily due to increased distribution revenue as a result of the 2013 and 2014 electric and natural gas distribution rate case orders issued by the Maryland PSC, increased cost recovery for energy efficiency and demand response programs (offset below in depreciation and amortization expense), and increased transmission revenue pursuant to increased rates effective June 2014.

The year-over-year increase in operating revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:

•

Decrease of $1,095 million at Generation due to mark-to-market losses of $591 million in 2014 from economic hedging activities compared to $504 million in mark-to-market gains in 2013.

•

Decrease of $16 million at ComEd due to unfavorable weather in the ComEd service territory.

Operating and maintenance expense increased by $1,298 million as compared to 2013 primarily due to the following unfavorable factors:

•

Increase in Generation’s labor, contracting and materials costs of $361 million primarily due to the inclusion of CENG’s results from April 1, 2014 through December 31, 2014, an increase of $44 million resulting from expenses recorded for a Constellation merger commitment, an increase of $54 million as a result of an increase in the number of planned nuclear refueling outage days at Generation, primarily related to the inclusion of CENG’s plants beginning April 1, 2014, and an increase of $16 million in the reserve for future asbestos-related bodily injury claims;

•

Increase in labor, contracting and materials costs of $56 million at ComEd associated with EIMA smart meter projects and $22 million at BGE due to increased maintenance activities;

•

Increase in Generation’s accretion expense of $78 million primarily due to the inclusion of CENG’s results from April 1, 2014 through December 31, 2014;

•

Long-lived asset impairments at Generation of $663 million in 2014 compared to $157 million in 2013.

•

Increased storm costs at PECO and BGE of $100 million and $21 million, respectively;

•

Increased spending on energy and efficiency programs and increased uncollectible accounts expense at ComEd of $93 million; and

•

Increased uncollectible accounts expense at BGE of $17 million.

The year-over-year increase in operating and maintenance expense was partially offset by the following favorable factor:

•

A reduction in pension and non-pension postretirement benefits expense of $178 million primarily at Exelon, Generation, and ComEd, resulting from plan design changes for certain OPEB plans and the favorable impact of higher actuarially assumed pension and OPEB discount rates for 2014, partially offset by the inclusion of CENG’s pension and non-pension postretirement benefits expense from April 1, 2014 through December 31, 2014.

Depreciation and amortization expense increased by $161 million primarily as a result of the inclusion of CENG’s results from April 1, 2014 through December 31, 2014, increased depreciation expense across the operating companies for ongoing capital expenditures, and higher regulatory asset amortization related to energy efficiency and demand response expenditures.

Exelon recorded $437 million at Generation as a result of gains recorded on the sales of ownership interest in certain generating stations in 2014.

Exelon recorded a $261 million gain upon consolidation of CENG resulting from the difference in fair value of CENG’s net assets as of April 1, 2014, and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing transactions between Generation and CENG. Additionally, Exelon recorded a $28 million bargain-purchase gain related to the Integrys acquisition.

Interest expense decreased by $291 million primarily as a result of a decrease in 2014 given ComEd’s 2013 remeasurement of Exelon’s like-kind exchange tax positions, offset at Exelon by an increase in 2014 related to financing activities associated with the pending PHI merger.

Other, net increased by $5 million primarily at Generation as a result of favorable settlements in 2014 of certain income tax positions on Constellation’s pre-acquisition 2009-2012 tax returns and the change in realized and unrealized gains and losses on NDT funds.

Exelon’s effective income tax rates for the years ended December 31, 2014 and 2013 were 26.8% and 37.6%, respectively. See Note 14—Income Taxes 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, 2014 and 2013, 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, 2014 were $2,068 million, or $2.39 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,149 million, or $2.50 per diluted share, for the same period in 2013. 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 attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the year ended December 31, 2014 as compared to 2013:


	For the years ended December 31,
	2014						2013
(All amounts after tax; in millions, except per share amounts)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	1,623		$	1.88		$	1,719		$	2.00
Mark-to-Market Impact of Economic Hedging Activities^(a)		363			0.42			(310	)		(0.35	)
Unrealized Gains Related to NDT Fund Investments^(b)		(86	)		(0.10	)		(78	)		(0.09	)
Plant Retirements and Divestitures^(c)		(245	)		(0.28	)		(13	)		(0.02	)
Asset Retirement Obligation^(d)		(13	)		(0.02	)		7			0.01
Merger and Integration Costs^(e)		185			0.21			87			0.08
Amortization of Commodity Contract Intangibles^(f)		64			0.07			347			0.41
Reassessment of State Deferred Income Taxes^(g)		(27	)		(0.03	)		4			—
Long-Lived Asset Impairments^(h)		435			0.50			110			0.14
Bargain-Purchase Gain on Integrys acquisition⁽ⁱ⁾		(28	)		(0.03	)		—			—
Gain on CENG Integration^(j)		(159	)		(0.18	)		—			—
Tax Settlements^(k)		(106	)		(0.12	)		—			—
CENG Non-Controlling Interest^(l)		62			0.07			—			—
Remeasurement of Like-Kind Exchange Tax Position^(m)		—			—			267			0.31
Midwest Generation Bankruptcy Charges⁽ⁿ⁾		—			—			16			0.02
Amortization of the Fair Value of Certain Debt^(o)		—			—			(7	)		(0.01	)

Adjusted (non-GAAP) Operating Earnings	$	2,068		$	2.39		$	2,149		$	2.50

(a)

Reflects the impact of losses (gains) for the years ended December 31, 2014 and December 31, 2013 (net of taxes of $232 million and ($201) million, respectively) on Generation’s economic hedging activities. See Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities.

(b)

Reflects the impact of unrealized gains for the years ended December 31, 2014 and December 31, 2013 (net of taxes of $(77) million and $(144) million, respectively) on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

(c)	Reflects the impacts associated with the sales of Generation’s ownership interests in generating stations for the years ended December 31, 2014 and December 31, 2013 (net of taxes of $(163) million and ($4) million, respectively).

(d)

Reflects the impacts of a decrease in Generation’s decommissioning obligation for the year ended December 31, 2014 (net of taxes of $(4) million). Reflects the impacts of an increase in Generation’s asset retirement obligation for asbestos at retired fossil plants for the year ended December 31, 2013 (net of taxes of $5 million).

(e)

Reflects certain costs incurred for the years ended December 31, 2014 and December 31, 2013 (net of taxes of $84 million and $33 million, respectively) including professional fees, employee-related expenses, integration activities, upfront credit facilities, merger commitments, and certain pre-acquisition contingencies, if and when applicable to the Constellation merger in 2013 and the Constellation merger, CENG integration, acquisition of Integrys Energy Services, Inc. (Integrys) and pending PHI acquisition in 2014.

(f)

Reflects the non-cash impact for the years ended December 31, 2014 and December 31, 2013 (net of taxes of $68 million and $219 million, respectively) of the amortization of intangibles assets, net, related to commodity contracts recorded at fair value at the 2012 Constellation merger date, the 2014 CENG integration date, and the 2014 Integrys acquisition date.

(g)	Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment.

(h)

In 2014, reflects charges to earnings related to the impairments of certain generating assets held for sale, Upstream assets, and wind generating assets (net of taxes of $250 million). In 2013, reflects a charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects and the impairment of certain wind generating assets (net of taxes of $69 million).

(i)	Reflects the excess of the fair value of assets and liabilities acquired over the purchase price for the Integrys acquisition (net of taxes of $(16) million) on November 1, 2014.

(j)	Reflects the non-cash gain recorded upon consolidation of CENG in accordance with the execution of the NOSA on April 1, 2014 (net of taxes of $(102) million).

(k)	Reflects a benefit related to the favorable settlement in 2014 of certain income tax positions on Constellation’s pre-acquisition 2009-2012 tax returns.

(l)	Pursuant to the April 1, 2014 consolidation, represents adjustments to account for the CENG interest not owned by Generation, where applicable.

(m)

For 2013, reflects a non-cash charge to earnings (net of taxes of $102 million) resulting from the remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets. See Note 14—Income Taxes of the Combined Notes to the Consolidated Financial Statements for additional information.

(n)	Reflects costs incurred in 2013 to establish estimated liabilities (net of taxes of $10 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.

(o)

Reflects the 2013 non-cash amortization of certain debt (net of taxes of ($5) million) recorded at fair value at the Constellation merger date which was retired in the second quarter of 2013. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.

Merger and Acquisition Costs

As discussed above, Exelon has incurred and will continue to incur costs associated with the Integrys and PHI acquisitions including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), financing costs, integration initiatives, and certain pre-acquisition contingencies.

For the year ended December 31, 2014, expense has been recognized for costs incurred to achieve the Constellation merger, CENG integration, Integrys acquisition and proposed PHI acquisition as follows:


	Pre-tax Expense
	Twelve Months Ended December 31, 2014
Merger Integration and Acquisition Costs:	Generation		ComEd		PECO		BGE		Exelon
Financing^(a)	$	—	$	—	$	—	$	—	$	131
Regulatory Commitments^(b)		44		—		—		—		44
Transaction^(c)		—		—		—		—		26
Employee-Related^(d)		5		—		—		—		5
Other^(e)		56		4		2		2		65

Total	$	105	$	4	$	2	$	2	$	271


	Pre-tax Expense
	Twelve Months Ended December 31, 2013
Merger Integration Costs:	Generation		ComEd		PECO		BGE		Exelon
Employee-Related^(d)	$	48	$	4	$	3	$	1	$	58
Other^(e)		58		12		6		5		84

Total	$	106	$	16	$	9	$	6	$	142

(a)	Reflects costs incurred at Exelon related to the financing of the PHI merger, including upfront credit facility fees.

(b)	Reflects costs incurred at Generation for a Constellation merger commitment.

(c)	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 transactions.

(d)

Costs primarily for employee severance, pension and OPEB expense and retention bonuses. ComEd established regulatory assets of $2 million for the year ended December 31, 2013. The majority of these costs are expected to be recovered over a five-year period. These costs are not included in the table above.

(e)

Costs to integrate CENG and Constellation processes and systems into Exelon and to terminate certain Constellation debt agreements. For the year ended December 31, 2014, also includes professional fees primarily related to integration for the proposed PHI acquisition. ComEd and BGE established regulatory assets of $9 million and $12 million, respectively, for the year ended December 31, 2013, for certain other merger and integration costs, which are not included in the table above.

As of December 31, 2014, Exelon projects incurring total additional PHI acquisition and integration related expenses of $650 million, of which approximately $100 million is expected to be capitalized to property, plant and equipment excluding the direct investment Exelon and PHI have proposed to the PHI utilities respective customers.

Pursuant to the conditions set forth by the MDPSC in its approval of the merger transaction, Exelon committed to provide a package of benefits to BGE customers, and make certain investments in the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. 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. On March 20, 2013, Generation signed a twenty-year lease agreement that was contingent upon the developer obtaining all required approvals, permits and

financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. The building is expected to be ready for occupancy in approximately 2 years. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information related to the lease commitments.

Exelon’s Strategy and Outlook for 2015 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. Exelon’s strategy is to leverage its integrated business model to create value and diversify its business. Exelon’s competitive and regulated businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:

•

Generation’s competitive businesses provide commodity exposure and a platform to diversify into adjacent markets, while providing residual dividend support.

•

Exelon’s utilities provide a foundation for stable earnings and dividend support, which translates to a stable currency in our stock.

Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change. While enhancing Exelon’s core value, it enables it to take advantage of a myriad of opportunities, rather than focusing on any one segment of the energy industry value chain.

Generation’s competitive businesses create value for customers by providing innovative solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide generation to load matching and that diversify the generation fleet by expanding Generation’s regional and technological footprint. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.

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. The Exelon utilities only invest in rate base where it provides a net benefit to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments prudently and at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of best practices to achieve improved operational and financial results. Combined, the utilities plan to invest approximately $16 billion over the next five years in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.

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.

Various market, financial, and other factors could affect the Registrants’ success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.

Proposed Merger with Pepco Holdings, Inc. (Exelon)

On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Exelon intends to fund the all-cash transaction using a combination of approximately $3.5 billion of debt, up to $1 billion cash from asset sales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). In addition, Exelon entered into a 364-day $7.2 billion senior unsecured bridge credit facility to support the contemplated transaction and provide flexibility for timing of permanent financing, which has subsequently been reduced to $3.2 billion as a result of execution of the debt and equity security issuances and the net after-tax cash proceeds from generating asset divestitures during the second half of 2014. See Note 4—Mergers, Acquisitions, and Divestitures, Note 13—Debt and Credit Agreements, and Note 19—Common Stock of the Combined Notes to Consolidated Financial Statements for further information related to these transactions. In connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $126 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities in PHI as of December 31, 2014, with additional investments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million. As part of the applications for approval of the merger, Exelon and PHI proposed a package of benefits to the PHI utilities’ respective customers, providing for direct investment of more than $100 million with the actual amount and timing of any related payments dependent upon settlement discussions in merger regulatory approval proceedings and the terms of regulatory orders approving the merger.

To date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU) and the FERC have approved the merger of PHI and Exelon. The Federal Communications Commission has also approved the transfer of certain PHI communications licenses. On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits to ACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregate value of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million.

Completion of the transaction also remains conditioned upon approval by the Public Services Commissions of the District of Columbia, Delaware and Maryland. Procedural schedules have been set in these commission proceedings and final approval decisions are expected in the first half of 2015.

On October 9, 2014, PHI and Exelon each received a request for additional information from the DOJ. The request had the effect of extending the DOJ review period until 30 days after PHI and Exelon each has certified that it has substantially complied with the request. On November 21, 2014, Exelon and PHI each certified that it had substantially complied with the request. Accordingly, the HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the merger, the DOJ has not advised Exelon or PHI that it has concluded its investigation. Exelon and PHI will continue to work cooperatively with the DOJ regarding the proposed merger.

Exelon and PHI continue to expect to complete the merger in the second or third quarter of 2015.

Through December 31, 2014, Exelon has incurred approximately $179 million of expense associated with the proposed merger, including $48 million related to acquisition and integration costs and $131 million of costs incurred to finance the transaction. The Merger Agreement also provides for termination rights for both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the transaction does not close due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities of PHI described above, as a result of PHI redeeming the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock.

Exelon has listed various potential risks relating to the pending merger with PHI (see Item 1A. Risk Factors), including difficulties that may be encountered in satisfying the conditions to completion of the merger and the potential for developments that might have an adverse effect on Exelon and the ability to realize the expected benefits of the merger. Exelon is taking steps to manage these risks and expects that the merger can be completed on a basis favorable to the company’s shareholders and customers. Accordingly, Exelon anticipates closing the transaction in the second or third quarter of 2015. Refer to Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the merger transaction.

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. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).

Capacity Market Changes in PJM. In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. To address this disconnect, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally seek to improve resource performance and reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. To cover capital and other costs and risks that suppliers would incur to meet these higher reliability standards, suppliers would be allowed to include adders for such costs as well as risk premiums in their capacity market offers. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments to suppliers. Exelon participated actively in PJM’s stakeholder process through which PJM developed the proposal and is also actively participating in the FERC proceeding including filing comments. PJM asked for a FERC order approving the proposal by April 1, 2015 so PJM can implement the proposal prior to its next capacity auction in May 2015. However, it is not clear when or how the FERC will respond to PJM’s proposal or, if it responds within PJM’s timeframe, whether FERC will require changes.

Subsidized Generation. The rate of expansion of subsidized generation, including low-carbon generation such as wind and solar 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 attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted in to law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, 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. CPV has subsequently sought to extend that date. The CfD mandated 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.

Exelon and others have challenged the constitutionality and other aspects of the New Jersey legislation and the actions taken by the MDPCS in state and federal courts. Ultimately, the Exelon parties prevailed in obtaining orders from the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit effectively undoing the actions taken by the New Jersey legislature and the MDPSC respectively. The matter has been appealed to the U.S. Supreme Court, and while the Court of Appeals decisions are helpful, there remains risk the Supreme Court will overrule the lower Courts.

As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions held in May 2012, 2013, and 2014. In addition, CPV has announced its intention to move forward with construction of its New Jersey and Maryland plants, with or without the challenged state subsidy. Nonetheless to the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon’s market driven position. While the court decisions in New Jersey and Maryland are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s market driven position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows. Exelon continues to monitor developments and participate in stakeholder and other processes to ensure that similar state subsidies are not developed. In addition, Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to specific generation providers or technologies, or that would threaten the reliability and value of the integrated electricity grid.

See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Maryland Order.

Energy Demand. Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity for ComEd and PECO, and no projected growth for electricity for BGE. ComEd, PECO and BGE are projecting load volumes to increase by 0.4%, 0.8% and (0.2)%, respectively, in 2015 compared 2014.

Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to

serve. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.

Strategic Policy Alignment

Exelon routinely reviews its hedging policy, dividend policy, 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 second quarter 2014 dividend of $0.31 per share on Exelon’s common stock. The second quarter dividend was paid on June 10, 2014 to shareholders of record on May 16, 2014. All future quarterly dividends require approval by Exelon’s board of directors.

Exelon’s board of directors declared the third quarter 2014 dividend of $0.31 per share on Exelon’s common stock. The third quarter dividend was paid on September 10, 2014 to shareholders of record on August 15, 2014.

Exelon’s board of directors declared the fourth quarter 2014 dividend of $0.31 per share on Exelon’s common stock. The fourth quarter dividend was paid on December 10, 2014 to shareholders of record on November 14, 2014.

Exelon’s board of directors declared the first quarter 2015 dividend of $0.31 per share on Exelon’s common stock. The first quarter dividend will be paid on March 10, 2015, to shareholders of record on February 13, 2015.

Exelon and Generation evaluate the economic viability of each of their generating units on an ongoing basis. Decisions regarding the future of economically challenged generating assets will be based primarily on the economics of continued operation of the individual plants. If Exelon and Generation do not see a path to sustainable profitability in any of their plants, Exelon and Generation will take steps to retire those plants to avoid sustained losses. Retirement of plants could materially affect Exelon’s and Generation’s results of operations, financial position, and cash flows through, among other things, potential impairment charges, accelerated depreciation and decommissioning expenses over the plants remaining useful lives, and ongoing reductions to operating revenues, operating and maintenance expenses, and capital expenditures.

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 2014 and 2015. This strategy has not changed as a result of recent and pending asset divestitures. 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, 2014, the percentage of

expected generation hedged for the major reportable segments was 93%-96%, 61%-64% and 31%-34% for 2015, 2016, and 2017 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation (which reflects the divestiture impact of Quail Run). Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well. See Note 4—Mergers, Acquisition and Dispositions for more detail regarding the divestitures.

Generation procures 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 50% of Generation’s uranium concentrate requirements from 2015 through 2019 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 commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

Growth Opportunities

With an emphasis on innovation and entrepreneurship, Exelon is currently pursuing growth in both the utility and competitive energy businesses. Identifying and capitalizing on emerging trends and technologies, Exelon plans to invest in new innovative technologies to compete with a new breed of energy players, leverage new technologies to create new or expand existing businesses, and improve productivity and efficiencies within our existing businesses. Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas.

Competitive Energy Businesses

Generation continues to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain.

•

Leveraging its competencies,

•

Generation’s 2014 acquisition of Integrys allows Generation to expand its retail footprint further in an industry sector that continues to mature and consolidate and provides hedging and diversification benefits to its existing portfolio.

•

Generation continues to pursue investment opportunities in renewables, in its nuclear uprate program and in the development of natural gas generation plants that is supported by the trend of increasing natural gas supply.

•

Investing in business diversification to position the company for the future,

•

Generation has launched a business in competitive distributed generation that capitalizes on the push toward a decentralized system.

•

Generation is also making investments across the natural gas value chain throughout North America, focusing initially on expansion of the existing Upstream and wholesale gas businesses, as well as entry into liquefied natural gas.

Regulated Energy Businesses

The proposed acquisition of PHI provides an opportunity to accelerate Exelon’s regulated growth and provide stable cash flows, earnings accretion, and dividend stability. Additionally, ComEd, PECO and BGE anticipate making significant future investments in infrastructure modernization, including smart meter and smart grid initiatives, storm hardening, and advanced reliability technologies. Upon obtaining various approvals, ComEd also plans to invest approximately $280 million to construct the Grand Prairie Gateway Transmission Line in Illinois alleviating identified congestion and enhancing reliability. ComEd, PECO and BGE invest in rate base where it provides a net benefit to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made prudently and at the lowest reasonable cost to customers.

See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Initiatives.

Liquidity

Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). 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 also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources—Credit Matters—Exelon Credit Facilities below.

Exposure to Worldwide Financial Markets. Exelon has exposure to worldwide financial markets including European banks. 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, 2014, approximately 29%, or $2.5 billion, of the Registrants’ aggregate total commitments were with European banks, excluding the unsecured bridge facility to provide financing for the proposed PHI acquisition. The credit facilities include $8.5 billion in aggregate total commitments of which $7.3 billion was available as of December 31, 2014, due to outstanding letters of credit. There were no borrowings under the Registrants’ credit facilities as of December 31, 2014. See Note 13—Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information on the credit facilities.

Tax Matters

See Note 14—Income Taxes 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 portfolios, 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., NOx, 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 tightened ozone NAAQS, to be finalized in late 2015, proposed for public comment in December 2014. These recently finalized or proposed 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 requires 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. Numerous entities challenged the CSAPR in the D.C. Circuit Court. On August 21, 2012, the D.C. Circuit Court of Appeals 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. On April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit Court decision and upheld CSAPR, and remanded the case to the D.C. Circuit Court to resolve the remaining implementation issues On November 21, 2014, the U.S. EPA issued an Interim Final Rule in which the Agency announced that it was tolling the effective dates for the CSAPR. The first phase of the CSAPR program started on January 1, 2015, with the second phase starting January 1, 2017. Also released on November 21, 2014, was a Notice of Data Availability under which the Agency proposed CSAPR allowance allocations to generating units for the first five years of the program, 2015-2020; these were identical to those previously identified in prior final rules related to the CSAPR.

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. 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 challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. On April 15, 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety.

In November 2014, the U.S. Supreme Court granted a petition for review of the MATS Rule filed by 20 states and a coalition of coal-fired electric generators. The U.S. Supreme Court announced that it will review a single, yet critical, aspect of the MATS Rule—whether the U.S. EPA properly considered compliance costs (e.g., pollution control capital expenditures and on-going operations and maintenance expense) in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. If the Court finds that the U.S. EPA acted unreasonably, then implementation of the rule would be delayed until the U.S. EPA corrects any deficiencies. It is likely that the U.S. Supreme Court will issue a decision sometime in 2015. Exelon has been participating in the case as an intervenor in support of the rule.

The U.S. EPA continued its regular, periodic review of the NAAQS standards. On November 25, 2014, the Agency proposed, for public comment, the establishment of a revised primary ozone standard in the range of 65-70 parts per billion (ppb) 8-hour average, a reduction from the 2008 ozone standard level of 75 ppb 8-hour average standard. The Agency is also requesting public comment on levels as low as 60 ppb 8-hour average. In its proposal, the Agency is also proposing to extend the “ozone season” on a state-by-state basis from its current May-September five-month period to include months before, and after, the traditional ozone season, depending on air quality monitoring data. Most CSAPR states are proposed to be subjected to a March to October “ozone season.” In its proposed rule, the Agency also elected to set the secondary standard at the same level and form as the primary standard. The Agency is expected to issue its final ozone NAAQS revision in October 2015. 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 currently expected regulations, such as the MATS regulation.

In addition to these NAAQS, the U.S. EPA also finalized nonattainment designations for certain areas in the United States for the 2010 one-hour SO2 standard on August 5, 2013, and indicated that additional nonattainment areas will be designated in a future rulemaking. U.S. EPA will require states to submit state implementation plans (SIPs) for nonattainment areas by March 25, 2015. With regard to Texas and Maryland, no nonattainment areas were identified in EPA’s final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions of counties, in each state were identified as nonattainment. Since the 2010 one-hour SO2 standard was finalized, EPA has issued a series of guidance documents, and proposed a Data Requirement Rule that will be finalized in the summer of 2015 related to requirements for states related to the application of air quality monitoring and modeling in state implementation plans. Nonattainment county compliance with the one-hour SO2 standard is required by March 25, 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the requirements of pending states’ SIPs to further reduce SO2 emissions in support of attainment of the one hour SO2 standard.

The cumulative impact of these air regulations could be to require fossil fuel-fired 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 NOx.

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In addition, as of December 31, 2014, Exelon had a $361 million net investment in coal-fired plants in Georgia subject to long-term leases extending through 2028 and 2030. 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, after the impairments recorded in the second quarter of 2013 and 2014, 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.

On January 15, 2013, EPA issued a final rule for 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. On June 25, 2013, President Obama announced “The President’s Climate Action Plan,” a summary of executive branch actions intended to: reduce carbon emissions; prepare the United States for the impacts of climate change; and lead international efforts to combat global climate change and prepare for its impacts. Concurrent with the announcement of the Administration’s plan, the President also issued a Memorandum for the Administrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 New Source Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the U.S. EPA Administrator to issue two sets of proposed rulemakings with regard to power plant carbon emissions under Section 111 of the Clean Air Act.

The U.S. EPA proposed a Section 111(b) regulation for new units in September 2013 that may result in material costs of compliance for CO2 emissions for new fossil-fuel electric generating units, particularly coal-fired units. The Climate Action Plan also required the U.S. EPA to propose by June 2014 GHG emission regulations for existing stationary sources under Section 111(d) of the Clean Air Act, and to issue final regulations by June 2015. That proposed rule was published in the Federal Register on June 16, 2014. The proposed rule establishes emission reduction targets for each state and provides flexibility for each state to determine how to achieve its required reductions, including heat rate improvements at coal-fired power plants, fuel switching from coal to gas, renewable generation and new nuclear facilities, demand side energy efficiency, and the use of market-based instruments. While the nature and impact of the final regulations is not yet known, to the extent that the rule results in emission reductions from fossil fuel fired plants, imposing some form of direct or indirect price of carbon in competitive electricity markets, Exelon’s overall low-carbon generation portfolio results would benefit.

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 October 14, 2014, the U.S. EPA’s final Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed at each facility to determine the best technology available, followed by an implementation period. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.

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Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, the impact of compliance with the final rule is unknown. Should a state permitting director determine that a facility is required to install cooling towers to comply with the rule, that facility’s economic viability would be called into question. However, the likely impact of the rule has been significantly decreased since the final rule does not mandate cooling towers as a national standard, and the state permitting director is required to apply a cost-benefit test and take into consideration site-specific factors.

Hazardous and Solid Waste. On December 19, 2014, the U.S. EPA issued the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants, including the classification of CCR as non-hazardous waste under RCRA. The EPA ruling is effective 180 days after publication in the Federal Register, which is anticipated in early 2015. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation is evaluating what, if any, incremental costs will be incurred for coal ash disposal sites formerly owned by Generation that have not yet been closed by their current owners. At this time, however, Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted for these former sites under the new federal regulations. For these reasons, Generation is unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations, and as a result no new liability has been recorded as of December 31, 2014.

See Note 22—Commitments and Contingencies 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

NRC Task Force Insights from the Fukushima Daiichi Accident. In July 2011, an NRC Task Force formed in the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, issued a report of its review of the accident, including tiered 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 NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. The NRC and its staff are continuing to evaluate additional requirements. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under review by the NRC 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 for Generation, net of expected co-owner reimbursements, for the period from 2015 through 2019 is expected to be between approximately $325 million and $350 million of capital (including approximately $75 million for the CENG plants) and $75 million of operating expense (including approximately $25 million for the CENG plants). As Generation completes the design and installation planning for its actions, Generation will update these estimates. Further, Generation estimates incremental costs of $15 to $20 million per unit at thirteen Mark 1 and II units (including two CENG units) for the installation of filters on 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

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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 and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Executive Overview of the Exelon 2014 Form 10-K, for additional information.

Financial Reform Legislation. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that applies to Exelon is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires the creation of a new regulatory regime for over-the-counter swaps (Swaps), including mandatory clearing for certain categories of Swaps, incentives to shift Swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. For non security-based Swaps including commodity Swaps, Dodd-Frank empowers the Commodity Futures Trading Commission (CFTC) to promulgate regulations implementing the law’s objectives. The primary aim of Dodd-Frank is to regulate the key intermediaries in the Swaps market, which entities are either swap dealers (SDs), major swap participants (MSPs), and certain other financial entities, but the law also applies to a lesser degree to end-users of Swaps. On January 12, 2015, President Obama signed into law a bill that exempts from margin requirements Swaps used by end-users to hedge or mitigate commercial risk. Moreover, the CFTC’s Dodd-Frank regulations preserve the ability of end users in the energy industry to hedge their risks using Swaps without being subject to mandatory clearing, and excepts or exempts end-users from many of the other substantive regulations. Accordingly, as an end-user, Generation is conducting its commercial business in a manner that does not require registration with the CFTC as an SD or MSP. Generation does not anticipate transacting in the future in a manner in which it would become a SD or MSP.

Energy Infrastructure Modernization Act. Since 2011, ComEd’s distribution rates are established through a performance-based rate formula, pursuant to EIMA. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. In addition, ComEd’s earned rate of return on common equity is required to be within plus or minus 50 basis points (“the collar”) of the target rate of return determined as the annual average rate on 30-year treasury notes plus 580 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on distribution revenue. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation.

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Formula Rate Tariff and Annual Reconciliation. On April 16, 2014, ComEd filed its annual distribution formula rate to request a total increase to the revenue requirement of $269 million. On December 11, 2014, the ICC issued its final order which increased the revenue requirement by $232 million, reflecting an increase of $160 million for the initial revenue requirement for 2014 and an increase of $72 million related to the annual reconciliation for 2013. Approximately $23 million of the total $37 million revenue requirement disallowance is recoverable through other rider-based mechanisms. The rate increase was set using an allowed return on capital of 7.06% (inclusive of an allowed return on common equity of 9.25% for 2014 less a performance metrics penalty of 5 basis points for the 2013 reconciliation). The rates took effect in January 2015. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC on January 28, 2015.

Grand Prairie Gateway Transmission Line. On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. On October 22, 2014, the ICC issued an order approving ComEd’s Grand Prairie Gateway Project over the objection of numerous landowners and the City of Elgin. Four parties filed timely applications for rehearing before the ICC. On November 25, 2014, the ICC denied the rehearing application filed by the Forest Preserve District of Kane County, but granted rehearing on the application of certain landowners who requested that the ICC consider an alternate route for a three-mile segment of the line in Kane County. The rehearing proceeding is currently pending and , the ICC must enter a final order on rehearing by April 24, 2015. On December 10, 2014, the ICC denied the remaining two applications for rehearing. On January 15, 2015, those two parties, the City of Elgin and the SKP landowner group and Utility Risk Management Corporation (collectively, the SKP/URMC party), each filed a Notice of Appeal with the Second District Appellate Court. On February 3, 2015, the ICC filed motions with the Second District Appellate Court seeking to extend the time for the ICC to file the record on appeal until after the ICC issues its Order on rehearing. The ICC also filed a motion to consolidate those appeals. ComEd expects to begin construction of the line in the second quarter of 2015 with an in-service date expected in the second quarter of 2017.

FERC Ameren Order. In July 2012, FERC issued an order to Ameren Corporation (Ameren) finding 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 filed for rehearing of the July 2012 order, which was denied in June 2014. FERC and Ameren are in the process of determining the amount of any potential refund. 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.

FERC Order No. 1000 Compliance. 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 required removal from all FERC-approved tariffs and agreements of a 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,

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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. On March 22, 2013, FERC issued an order on the PJM Compliance Filing and the filing of these PJM Transmission Owners (1) rejecting the arguments of those PJM Transmission Owners that changes to the PJM governing documents were entitled to review under the Mobile-Sierra standard, (2) accepting most of the PJM filing, removing the right-of-first refusal from the PJM tariffs, and (3) directing PJM to remove certain exceptions that it included in its compliance filing that FERC found did not comply with Order No. 1000. FERC’s order 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. Numerous parties sought rehearing of the FERC’s March 22, 2013 order, including the PJM Transmission Owners who sought rehearing of the FERC’s rejection of their Mobile-Sierra and related arguments. PJM’s compliance filing was made on July 22, 2013. On May 15, 2014, FERC denied the rehearing requests except with respect to one issue on when PJM could consider state and local laws in evaluating projects. FERC generally accepted the July 22, 2013, Compliance Filing but required several minor additional changes. FirstEnergy and at least one other party filed an appeal of the May 15, 2014, Order upholding PJM’s right of first refusal language in the DC Circuit. Exelon has intervened in the FirstEnergy appeal. Several parties have filed requests for rehearing or clarification concerning the changes set forth in the May 15, 2014, Order. On December 18, 2014, FERC issued an order conditionally accepting part of the PJM-MISO interregional Order No. 1000 compliance filing, rejecting a MISO proposal concerning cost allocation for cross-border reliability projects and directing a further compliance filing by PJM and MISO.

FERC Transmission Complaint. On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the Pepco Holdings, Inc. companies relating to their respective transmission formula rates. BGE’s formula rate includes a 10.8% base rate of return on common equity (ROE) and a 50 basis point incentive for participating in PJM (the latter of which is conditioned upon crediting the first 50 basis points of any incentive ROE adders). The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the revenues subject to refund are limited to a fifteen month period, the earliest date from which the base ROE could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint.

On August 21, 2014, FERC issued an order in the BGE and PHI companies’ proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013. BGE, the PHI companies and the parties began settlement discussions under the guidance of a FERC administrative law judge on September 23, 2014. On November 24, 2014, the Settlement Judge informed FERC and the Chief Judge that the parties had reached an impasse and determined that a settlement was not possible. The Settlement Judge recommended termination of settlement proceedings. On November 26, 2014, the Chief Judge issued an order terminating the settlement proceeding, designating a presiding judge at the hearings and directing that an initial decision be issued by November 25, 2015.

On December 8, 2014, various state agencies in Delaware, Maryland, New Jersey, and D.C. filed a second complaint against BGE regarding the base ROE of the transmission business seeking a

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reduction from 10.8% to 8.8%. The filing of the second complaint creates a second refund window. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants’ requested refund effective date of December 8, 2014.

Based on the current status of the complaint filings, BGE believes it is probable that BGE’s base ROE rate will be adjusted, and that a refund to customers of transmission revenue for the two maximum fifteen month periods will be required. However, BGE is unable to estimate the most likely refund amount for either complaint at this time, and has therefore established a reserve, which is not material, representing the low end of a reasonably possible estimated range of loss. Additionally, management is unable to estimate the maximum exposure of a potential refund at this time, which may have a material impact on BGE’s results of operations and cash flows. The estimated annual ongoing reduction in revenues if FERC approved the ROEs requested by the parties in their filings is approximately $11 million. If FERC were to order a reduction of BGE’s base ROE to 8.7% as sought in the first complaint (while retaining the 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment), the result of the first fifteen month refund window would be a refund to customers of approximately $13 million. If FERC were to order a reduction in BGE’s base ROE to 8.8% as sought in the second complaint (while retaining 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment) and the refund period extended for a full fifteen months, the result would be a refund to customers of approximately $14 million. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

The Maryland Strategic Infrastructure Development and Enhancement Program. In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On March 26, 2014, the MDPSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. On November 17, 2014, BGE filed a surcharge update including a true-up of costs estimates included in the 2014 surcharge, along with its 2015 project list and cost estimates to be included in the 2015 surcharge. The filing was approved with a revised surcharge effective January 1, 2015. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2015 project list and the proposed surcharge for 2015. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial to Exelon and BGE as of December 31, 2014.

In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE’s infrastructure replacement plan. On September 5, 2014, the Baltimore City Circuit Court affirmed the MDPSC decision on BGE’s infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential

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consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court, however, a procedural schedule for the matter has not yet been set.

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 accounting policies described below require significant judgment in their application, or 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’s ARO associated with decommissioning its nuclear units was $7.0 billion at December 31, 2014. 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

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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. Generation assumes DOE will begin accepting SNF in 2025. The SNF acceptance date was based on management’s estimates of the amount of time required for 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 22—Commitments and Contingencies 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. The current NRC license for Oyster Creek expires in 2029. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. As a result of this decision the expected economic 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. Generation has successfully secured 20-year operating license renewal extensions for seventeen 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 has been denied. For its remaining seven operating units, Generation is in various stages of the process of pursuing similar extensions and has filed license renewal applications for six operating nuclear units and has until 2021 to seek license renewal for one operating nuclear unit. 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 seventeen 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 $300 million per unit as of December 31, 2014. 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 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 $7.0 billion to approximately $8.6 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, 2014 at fair value of approximately $10.5 billion and have an estimated targeted annual pre-tax return of 6.0% to 6.3%.

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 2013 CARFRs rather than the 2014 CARFRs in performing its third quarter 2014 ARO update, Generation would have reduced the ARO by approximately $190 million as compared to

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the actual decrease to the ARO of $125 million; and ii) if the CARFR used in performing the third quarter 2014 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 decreased by $230 million and increased $40 million, respectively, as compared to the actual decrease of $125 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.

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 (Decrease) to ARO at December 31, 2014
Cost escalation studies
Uniform increase in escalation rates of 25 basis points	$	810
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	$	290
Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of the SAFSTOR scenario by 10 percentage points	$	420
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	$	630
Extend the estimated date for DOE acceptance of SNF to 2030	$	230
Extend the estimated date for DOE acceptance of SNF to 2030 coupled with an increase in discount rates of 100 basis points	$	(270	)
Extend the estimated date for DOE acceptance of SNF to 2030 coupled with a decrease in discount rates of 100 basis points	$	1,100

For more information regarding accounting for nuclear decommissioning obligations, see Note 1—Significant Accounting Policies and Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements.

Goodwill (Exelon and ComEd)

As of December 31, 2014, Exelon’s and ComEd’s carrying amount of goodwill was approximately $2.7 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 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 one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment for its combined business. There is no level below this operating segment for which operating results are regularly reviewed by segment management. Therefore, ComEd’s operating segment is considered its only reporting unit.

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Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. 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 quantitative 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 accounting 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. See Note 1—Significant Accounting Policies, Note 10—Intangible Assets and Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Purchase Accounting (Exelon and Generation)

In accordance with the authoritative accounting guidance, the assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed 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—Mergers, Acquisitions, and Dispositions 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, Acquisitions, and Dispositions and Note 10—Intangible Assets of the Combined Notes to Consolidated Financial Statements for further discussion.

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

Exelon, Generation, ComEd, PECO and BGE regularly monitor and 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. Indicators for impairment may include a 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.

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 as well as the associated intangible contract assets recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from the 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. In certain cases generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables).

On a quarterly basis, Generation assesses its asset groups for indicators of impairment. If indicators are present, a recoverability test is performed. Impairment may occur if 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 often 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 judgment, the resulting fair market value would be different. As such, the determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial and industry sources. An impairment determination would require the affected Registrant to reduce the value of either the long-lived asset or asset group, including any associated intangible contract assets and liabilities, as well as current period earnings by the amount of the impairment.

Generation evaluates natural gas and oil Upstream properties at least annually to determine if they are impaired. Impairment for natural gas and oil Upstream properties occurs if there are no firm plans to continue drilling, lease expiration is at risk, historical experience indicates a decline in carrying value below fair value or the price of the underlying commodity significantly declines.

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Exelon holds investments in coal-fired plants in Georgia subject to long-term leases. The investments are accounted for as direct financing lease investments. The investments represent the estimated residual values of the leased assets at the end of the respective lease terms. On an annual basis, Exelon reviews the estimated residual values of its direct financing lease investments and records an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, that takes into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contracts associated with the plants given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements.

Generation also evaluates its equity method investments to determine whether or not they are impaired based on whether the investment has experienced a decline in value that is not temporary in nature. Additionally, if one of Generation’s equity method investments recognizes an impairment, Generation would record its proportionate share of that impairment loss through its equity earnings (losses) of unconsolidated affiliates.

See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment evaluations made by Exelon.

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 Registrants complete depreciation studies every five years, or more frequently in an event, regulation action, or change in retirement patterns indicate an update is necessary. 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—Significant Accounting Policies 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 annually the estimated service lives of its generating facilities based on feasibility assessments as well as economic and capital requirements. The estimated service lives of hydroelectric facilities are based on the

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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 completed a depreciation study and filed the updated depreciation rates with both FERC and the ICC in January 2014. This resulted in the implementation of new depreciation rates effective first quarter 2014.

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. PECO expects to complete an updated depreciation study in 2015 and expects this to result in new depreciation rates effective in the first quarter of 2015 for electric transmission assets and first quarter 2016 for electric distribution and gas assets.

The MDPSC does not mandate the frequency or timing of BGE’s depreciation studies. In July 2014, 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 and effective December 15, 2014.

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 16—Retirement Benefits 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 affected 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 participant 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 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.

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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 16—Retirement Benefits 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 EROA assumption used in calculating pension costs was 7.00%, 7.50% and 7.50% for 2014, 2013 and 2012, respectively. The weighted average EROA assumption used in calculating other postretirement benefit costs was 6.59%, 6.45% and 6.68% in 2014, 2013 and 2012, 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. Over time, Exelon has decreased its equity investments and increased its investments in fixed income securities and alternative investments within the pension asset portfolio in order to achieve a balanced portfolio of liability hedging and return-generating assets. See Note 16—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s asset allocations. Exelon used an EROA of 7.00% and 6.46% to estimate its 2015 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, 2014 were 10.93% and 5.01%, respectively, compared to an expected long-term return assumption of 7.00% and 6.59%, respectively.

Discount Rate. The discount rates used to determine the majority pension and other postretirement benefit obligations were 3.94% and 3.92%, respectively, at December 31, 2014. The discount rates at December 31, 2014 represent weighted-average rates for the majority of pension and other postretirement benefit plans. At December 31, 2014 and 2013, 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 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 used discount rates ranging from 3.94% and 3.92% to estimate the majority its 2015 pension and other postretirement benefit costs, respectively.

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Health Care Reform Legislation. In March 2010, the Health Care Reform Acts (the Acts) were signed into law. The 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. Although Exelon has capped the rate of claims growth for certain legacy Exelon plan participants over age 65, exposure to the excise tax remains. 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 under what circumstances pre- and post-65 retiree benefits 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 impact the costs reported for Exelon’s other postretirement benefit plans for participant populations with plan designs that do not have a cap on cost growth. 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. Exelon assumed an initial health care cost trend rate of 6.00% for 2014, decreasing to an ultimate health care cost trend rate of 5.00% in 2017.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon historically used a mortality base table for its accounting valuation that is consistent with the IRS required table for funding (referred to as RP-2000) and its corresponding improvement scale. During 2014, the Society of Actuaries (SOA) issued an updated mortality table (referred to as RP-2014) and improvement scale that suggests significant mortality improvement over the prior table. Exelon has a substantial employee population that provides a credible basis for mortality evaluation. Exelon engaged its actuaries to conduct a mortality study of Exelon’s actual experience over a five year period as compared to the RP-2000 and RP-2014 tables, which resulted in a determination that the RP-2000 more closely aligns with Exelon’s actual mortality experience. The study also considered available improvement scales. Management concluded that the RP-2000 and a more recent improvement scale issued by the SOA with certain adjustments to long-term improvement rates represent its best estimate of mortality. Exelon is utilizing the Scale BB 2-Dimensional improvement scale with long-term improvements of 0.75% (as compared to the 1% incorporated in the issued table) for its mortality improvement assumption. The change in assumption resulted in increases of $361 million and $117 million in the pension and other postretirement benefits obligations, respectively and an increase in 2015 cost of $45 million and $20 million for pension and other postretirement benefits, respectively.

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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 2014 cost:
Discount rate^(a)	0.5%	$	(71	)	$	(34	)	$	(105	)
	(0.5)%		69			31			100
EROA	0.5%		(71	)		(12	)		(83	)
	(0.5)%		71			12			83
Health care cost trend rate ^(b)	1.00%		N/A			35			35
	(1.00)%		N/A			(24	)		(24	)
Change in benefit obligation at December 31, 2014:
Discount rate^(a)	0.5%		(1,053	)		(245	)		(1,298	)
	(0.5)%		1,156			271			1,427
Health care cost trend rate ^(b)	1.00%		N/A			162			162
	(1.00)%		N/A			(113	)		(113	)

(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.

(b)	Changes in the plan design of certain other postretirement benefit plans have resulted in reduced sensitivity to the health care cost trend rate.

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 11.8 years, 11.8 years and 11.9 years for the years ended December 31, 2014, 2013 and 2012, 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 9.1 years, 8.7 years and 8.9 years for the years ended December 31, 2014, 2013 and 2012, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 10.1 years, 9.8 years and 10.1 years for the years ended December 31, 2014, 2013 and 2012, 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

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accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. As of December 31, 2014, 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—Regulatory Matters 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 had a financial swap contract with Generation that expired May 31, 2013 and currently holds floating-to-fixed energy swaps with several unaffiliated suppliers that extend into 2032. PECO and BGE have entered into derivative natural gas contracts to hedge their 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

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Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether or not a contract qualifies as a derivative under this guidance requires that management exercise significant judgment, including assessing the market liquidity as well as determining whether a contract has one or more underlyings and one or more notional amounts. Further, interpretive guidance related to the authoritative literature continues to evolve, including how it applies to energy and energy-related products. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance related to derivatives, could result in previously excluded contracts being subject to the provisions of the authoritative derivative guidance. Generation has determined that contracts to purchase uranium, 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 the Constellation merger, 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 Constellation 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 Constellation 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. In addition, for energy-related derivatives entered into for proprietary trading purposes, changes in the fair value of the derivatives are recognized in earnings each period. For economic hedges that are not designated for hedge accounting for ComEd, PECO and BGE, changes in the fair value each period are recorded as a regulatory asset or liability.

Normal Purchases and Normal Sales Exception. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While 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

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on an accrual basis of accounting. 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. The contracts that ComEd has entered into with 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.

Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. 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 derivatives’ pricing is verified 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 derivatives are traded predominately at liquid trading points. The remaining derivative contracts are 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 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 derivatives that trade in less liquid markets with limited pricing information, 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.

Interest Rate and Foreign Exchange 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

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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. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. 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 and foreign exchange curves. As these inputs are based on observable data and valuations of similar instruments, the interest rate and foreign exchange derivatives are primarily categorized in Level 2 in the fair value hierarchy. Certain exchange based interest rate derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 11—Fair Value of Financial Assets and Liabilities and Note 12—Derivative Financial Instruments 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, 2014 and 2013 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of tax matters could result in favorable or

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unfavorable adjustments to their consolidated financial statements and such adjustments could be material. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding taxes.

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 22—Commitments and Contingencies 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)

Sources of Revenue and Selection of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of energy and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of electricity and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.

The appropriate accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable accounting standards. The Registrants primarily use accrual and mark-to-market accounting as discussed in more detail below.

Accrual Accounting. Under accrual accounting, the Registrants record revenues in the period when services are rendered or energy is delivered to customers. The Registrants generally use accrual accounting to recognize revenues for sales of electricity, natural gas, and other commodities as part of their physical delivery activities. The Registrants enter into these sales transactions using a variety of instruments, including non-derivative agreements, derivatives that qualify for and are designated as

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normal purchases and normal sales (NPNS) of commodities that will be physically delivered, sales to utility customers under regulated service tariffs, and spot-market sales, including settlements with independent system operators.

Mark-to-Market Accounting. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that meet the definition of a derivative for which they are not permitted, or have not elected, the NPNS exception. These mark-to-market transactions primarily relate to risk management activities and economic hedges of other accrual activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable and realized; and unrealized gains and losses from changes in the fair value of open contracts.

Use of Estimates. 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 affected by, among other things, variances in costs incurred and investments made and actions by regulators or courts.

Unbilled Revenues. The determination of Generation’s, ComEd’s, PECO’s and BGE’s retail energy sales to individual customers 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 or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable 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.

See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

Regulated Transmission & Distribution Revenues. ComEd’s EIMA distribution formula rate tariff 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 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 affected by, among other things, variances in costs incurred and investments made and actions by regulators or courts.

ComEd’s and BGE’s FERC transmission formula rate tariffs 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 affected by, among other things, variances in costs incurred and investments made and actions by regulators or courts.

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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 aging 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 customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accounts on customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance for uncollectible accounts, which was consistent with ComEd and PECO, as described above. 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. 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 6—Accounts Receivable 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, 2014, 2013 and 2012 set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Net Income Attributable to Common Shareholders by Registrant


	2014^(b)		2013		Favorable (unfavorable) 2014 vs. 2013 variance			2012 ^(a)			Favorable (unfavorable) 2013 vs. 2012 variance
Exelon	$	1,623	$	1,719	$	(96	)	$	1,160		$	559
Generation		835		1,070		(235	)		562			508
ComEd		408		249		159			379			(130	)
PECO		352		388		(36	)		377			11
BGE		198		197		1			(9	)		206

(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.

(b)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis from April 1, 2014, through December 31, 2014.

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Results of Operations—Generation


	2014^(c)			2013			Favorable (unfavorable) 2014 vs. 2013 variance			2012 ^(b)			Favorable (unfavorable) 2013 vs. 2012 variance
Operating revenues	$	17,393		$	15,630		$	1,763		$	14,437		$	1,193
Purchased power and fuel expense		9,925			8,197			(1,728	)		7,061			(1,136	)

Revenue net of purchased power and fuel expense ^(a)		7,468			7,433			35			7,376			57

Other operating expenses
Operating and maintenance		5,566			4,534			(1,032	)		5,028			494
Depreciation and amortization		967			856			(111	)		768			(88	)
Taxes other than income		465			389			(76	)		369			(20	)

Total other operating expenses		6,998			5,779			(1,219	)		6,165			386
Equity in (losses) earnings of unconsolidated affiliates		(20	)		10			(30	)		(91	)		101
Gain (loss) on sales of assets		437			13			424			(7	)		20
Gain on consolidation and acquisition of businesses		289			—			289			—			—

Operating income		1,176			1,677			(501	)		1,113			564
Other income and (deductions)
Interest expense		(356	)		(357	)		1			(301	)		(56	)
Other, net		406			355			51			246			109

Total other income and (deductions)		50			(2	)		52			(55	)		53

Income before income taxes		1,226			1,675			(449	)		1,058			617
Income taxes		207			615			408			500			(115	)

Net income		1,019			1,060			(41	)		558			502
Net income (loss) attributable to noncontrolling interest		184			(10	)		194			(4	)		(6	)

Net income attributable to membership interest	$	835		$	1,070		$	(235	)	$	562		$	508

(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.

(c)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis from April 1, 2014 through December 31, 2014.

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Net Income Attributable to Membership Interest

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Generation’s net income attributable to membership interest decreased compared to the same period in 2013 primarily due to higher operating and maintenance expense and higher depreciation expense; partially offset by higher revenue, net of purchase power and fuel expense, higher other income, the gains recorded on the sale of Generation’s ownership interest in generating stations, the bargain-purchase gain recorded related to the Integrys acquisition, and the gain recorded upon consolidation of CENG. The increase in operating and maintenance expense was largely due to increased labor contracting and materials expense due to the inclusion of CENG’s results beginning April 1, 2014 and impairment charges related to 1) generating assets held-for-sale, 2) certain Upstream assets, and 3) wind generating assets. The increase in revenue, net of purchased power and fuel expense was primarily due to the inclusion of CENG’s results beginning April 1, 2014, a decrease in fuel costs related to the cancellation of DOE spent nuclear fuel disposal fees, an increase in capacity prices, and favorable portfolio management activities in the New England an South regions, partially offset by lower realized energy prices related to executing Exelon’s ratable hedging strategy, higher procurement costs for replacement power due to extreme cold weather in the first quarter of 2014, and unrealized mark-to-market losses in 2014. The increase in other income is primarily the result of increased realized and unrealized gain on NDT funds.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. Generation’s net income attributable to membership interest increased compared to the same period in 2012 primarily due to higher revenue, net of purchased power and fuel expense, lower operating and maintenance expense and higher earnings from Generation’s interest in CENG; partially offset by impairment of certain generating assets, higher depreciation expense, higher property taxes, and higher interest expense. The increase in revenue, net of purchased power and fuel expense was primarily due to increased capacity prices and higher nuclear volume, partially offset by lower realized energy prices, higher nuclear fuel costs, and lower mark-to-market gains in 2013. The decrease in operating and maintenance expense was largely due to 2012 costs associated with a settlement with FERC in 2012 and decreases in transaction costs and employee-related costs associated with the merger.

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:

•

Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO excluding MISO’s Southern Region, 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 New York ISO, 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.

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•

Other Regions not considered individually significant:

•

South represents operations in the FRCC, MISO’s Southern Region, 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.

•

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 gas and oil exploration and production activities, proprietary trading, distributed generation, 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 and investments in energy-related proprietary technology. 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 the fourth quarter of 2012; unrealized mark-to-market impact of economic hedging activities; amortization of certain intangible assets relating to commodity contracts recorded at fair value and other miscellaneous revenues.

Generation evaluates the operating performance of its power marketing activities and allocates resources 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.

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For the years ended December 31, 2014 compared to 2013 and December 31, 2013 compared to 2012, Generation’s revenue net of purchased power and fuel expense by region were as follows:


							2014 vs. 2013									2013 vs. 2012
	2014			2013			Variance			% Change			2012 ^(a)			Variance			% Change
Mid-Atlantic^(b)(c)(g)	$	3,417		$	3,270		$	147			4.5	%	$	3,433		$	(163	)		(4.7	)%
Midwest^(d)		2,594			2,586			8			0.3	%		2,998			(412	)		(13.7	)%
New England		351			185			166			89.7	%		196			(11	)		(5.6	)%
New York^(b)(g)		483			(4	)		487			n.m.			76			(80	)		(105.3	)%
ERCOT		317			436			(119	)		(27.3	)%		405			31			7.7	%
Other Regions^(e)		327			201			126			62.7	%		131			70			53.4	%

Total electric revenue net of purchased power and fuel expense		7,489			6,674			815			12.2	%		7,239			(565	)		(7.8	)%
Proprietary Trading		42			(8	)		50			n.m.			(14	)		6			42.9	%
Mark-to-market gains (losses)		(591	)		504			(1,095	)		n.m.			515			(11	)		(2.1	)%
Other^(f)		528			263			265			100.8	%		(364	)		627			n.m.

Total revenue net of purchased power and fuel expense	$	7,468		$	7,433		$	35			0.5	%	$	7,376		$	57			0.8	%

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

(b)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis from April 1, 2014 through December 31, 2014.

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

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

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

(f)

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 of $124 million, $488 million, and $1,098 million pre-tax for the twelve months ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively.

(g)

Includes $113 million and $169 million of purchased power from CENG prior to its consolidation on April 1, 2014 in the Mid-Atlantic and New York regions, respectively, for the year ended December 31, 2014. Includes $542 million and $450 million of purchased power from CENG in the Mid-Atlantic and New York regions, respectively, for the year ended December 31, 2013. Includes $487 million and $306 million of purchased power from CENG in the Mid-Atlantic and New York regions, respectively, for the year ended December 31, 2012. See Note 25—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.

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Generation’s supply sources by region are summarized below:


					2014 vs. 2013								2013 vs. 2012
Supply source (GWh)	2014		2013		Variance			% Change			2012 ^(a)		Variance			% Change
Nuclear generation^(b)
Mid-Atlantic		58,809		48,881		9,928			20.3	%		47,337		1,544			3.3	%
Midwest		94,000		93,245		755			0.8	%		92,525		720			0.8	%
New York		13,645		—		13,645			n.m.			—		—			—	%

		166,454		142,126		24,328			17.1	%		139,862		2,264			1.6	%

Fossil and renewables^(b)
Mid-Atlantic ^(b)(d)		11,025		11,714		(689	)		(5.9	)%		8,808		2,906			33.0	%
Midwest		1,372		1,478		(106	)		(7.2	)%		971		507			52.2	%
New England		5,233		10,896		(5,663	)		(52.0	)%		9,965		931			9.3	%
New York		4		—		4			n.m.			—		—			n.m.
ERCOT		7,164		6,453		711			11.0	%		6,182		271			4.4	%
Other Regions ^(e)		7,955		6,664		1,291			19.4	%		5,913		751			12.7	%

		32,753		37,205		(4,452	)		(12.0	)%		31,839		5,366			16.9	%

Purchased power
Mid-Atlantic^(c)		6,082		14,092		(8,010	)		(56.8	)%		20,830		(6,738	)		(32.3	)%
Midwest		2,004		4,408		(2,404	)		(54.5	)%		9,805		(5,397	)		(55.0	)%
New England		12,354		7,655		4,699			61.4	%		9,273		(1,618	)		(17.4	)%
New York^(c)		2,857		13,642		(10,785	)		(79.1	)%		11,457		2,185			19.1	%
ERCOT		10,108		15,063		(4,955	)		(32.9	)%		23,302		(8,239	)		(35.4	)%
Other Regions ^(e)		14,795		14,931		(136	)		(0.9	)%		17,327		(2,396	)		(13.8	)%

		48,200		69,791		(21,591	)		(30.9	)%		91,994		(22,203	)		(24.1	)%

Total supply by region^(f)
Mid-Atlantic^(g)		75,916		74,687		1,229			1.6	%		76,975		(2,288	)		(3.0	)%
Midwest ^(h)		97,376		99,131		(1,755	)		(1.8	)%		103,301		(4,170	)		(4.0	)%
New England		17,587		18,551		(964	)		(5.2	)%		19,238		(687	)		(3.6	)%
New York		16,506		13,642		2,864			21.0	%		11,457		2,185			19.1	%
ERCOT		17,272		21,516		(4,244	)		(19.7	)%		29,484		(7,968	)		(27.0	)%
Other Regions ^(e)		22,750		21,595		1,155			5.3	%		23,240		(1,645	)		(7.1	)%

Total supply		247,407		249,122		(1,715	)		(0.7	)%		263,695		(14,573	)		(5.5	)%

(a)	Includes results for Constellation 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 includes the total output of plants that are fully consolidated (e.g. CENG). Nuclear generation for the year ended December 31, 2014 includes physical volumes of 11,408 GWh in Mid-Atlantic and 13,645 GWh in New York for CENG.

(c)

Purchased power includes physical volumes of 2,489 GWh, 12,067 GWh, and 9,925 GWh in the Mid-Atlantic and 2,857 GWh, 12,165 GWh, and 9,350 GWh in New York as a result of the PPA with CENG for the years ended December 31, 2014, 2013, and 2012, respectively. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, 100% of CENG volumes are included in nuclear generation.

(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 the fourth quarter of 2012 as a result of the Exelon and Constellation merger.

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

(f)	Excludes physical proprietary trading volumes of 10,571 GWh, 8,762 GWh, and 12,958 GWh for the years ended December 31, 2014, 2013, and 2012, respectively.

(g)

Includes sales to PECO through the competitive procurement process of 2,520 GWh, 5,070 GWh, and 7,762 GWh for the years ended December 31, 2014, 2013, and 2012, respectively. Sales to BGE of 5,093 GWh, 5,595 GWh, and 3,766 GWh were included for the years ended December 31, 2014, 2013, and 2012, respectively.

(h)	Includes sales to ComEd under the RFP procurement of 5,259 GWh, 7,491 GWh and 4,152 GWh for the years ended December 31, 2014, 2013, and 2012, respectively.

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Mid-Atlantic

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in revenue net of purchased power and fuel expense in the Mid-Atlantic of $147 million was primarily due to the consolidation of CENG, the cancellation of the DOE spent nuclear fuel disposal fees, and favorable portfolio management optimization activities, partially offset by higher procurement costs for replacement power, lower nuclear volumes (excluding CENG), lower capacity revenues, and lower realized energy prices related to executing Generation’s ratable hedging strategy.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic of $163 million was primarily due to lower realized energy prices and increased nuclear fuel costs, partially offset by the addition of Constellation in 2012, higher capacity revenues, and higher nuclear revenues.

Midwest

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in revenue net of purchased power and fuel expense in the Midwest of $8 million was primarily due to higher capacity prices, higher nuclear volumes, and the cancellation of the DOE spent nuclear fuel disposal fee, partially offset by lower realized energy prices related to executing Generation’s ratable hedging strategy.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The decrease in revenue net of purchased power and fuel expense in the Midwest of $412 million was primarily due to lower realized energy prices, increased nuclear fuel costs, and lower capacity revenues, partially offset by higher nuclear revenues.

New England

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The $166 million increase in revenue net of purchased power and fuel expense in New England is primarily due to higher realized energy prices and favorable impacts from the restructuring of a fuel supply contract, partially offset by lower generation volume.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The $11 million decrease in revenue net of purchased power and fuel expense in New England is primarily due to lower realized energy prices, partially offset by the addition of Constellation in 2012. 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, 2014 Compared to Year Ended December 31, 2013. The $487 million increase in revenue net of purchased power and fuel expense in New York was primarily due to the consolidation of CENG.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The $80 million decrease in revenue net of purchased power and fuel expense in New York was primarily due to decreased realized energy prices, partially offset by the addition of Constellation. Prior to the merger, New York was not a significant contributor to revenue net of purchased power and fuel expense at Generation.

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ERCOT

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The $119 million decrease in revenue net of purchased power and fuel expense in ERCOT was primarily due to higher procurement costs for replacement power in the second quarter of 2014 and the termination of an energy supply contract with a retail power supply company that was previously a consolidated variable interest entity. As a result of the termination, Generation no longer has a variable interest in the retail supply company and ceased consolidation of the entity during the third quarter of 2013. The decreases were partially offset by higher generation volume in the first quarter of 2014.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The $31 million increase in revenue net of purchased power and fuel expense in ERCOT was primarily due to increased realized energy prices and the addition of Constellation in 2012, partially offset by a decrease due to the termination of an energy supply contract with a retail power supply company that was previously a consolidated variable interest entity. As a result of the termination, Generation no longer has a variable interest in the retail supply company and ceased consolidation of the entity during the third quarter of 2013.

Other Regions

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The $126 million increase in revenue net of purchased power and fuel expense in Other Regions was primarily due to higher generation volumes and higher realized energy prices.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The $70 million increase in revenue net of purchased power and fuel expense in Other Regions was primarily as a result of the addition of Constellation in 2012, in addition to increased renewable generation.

Mark-to-market

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. 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 $591 million in 2014 compared to gains of $504 million in 2013. See Note 11—Fair Value of Financial Assets and Liabilities and Note 12—Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. 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 $504 million in 2013 compared to gains of $515 million in 2012. See Note 11—Fair Value of Financial Assets and Liabilities and Note 12—Derivative Financial Instruments 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, 2014 Compared to Year Ended December 31, 2013. The $265 million increase in other revenue net of purchased power and fuel was primarily due to a reduction in amortization of in-the-money energy contracts recorded at fair value at the Constellation merger date and an increase related to the amortization of out-of-the money energy contracts recorded at fair value

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upon the consolidation of CENG partially offset by a loss on gas inventory from lower of cost or market adjustments in 2014. See Note 10—Intangible Assets of the Combined Notes to Consolidated Financial Statements for information regarding contract intangibles.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The $627 million increase in other revenue net of purchased power and fuel was primarily due to reduced amortization expense of the acquired energy contracts recorded at fair value at the merger date. In addition, the increase is also attributable to results from activities acquired as part of the 2012 merger with Constellation including retail gas, energy efficiency, energy management and demand response, Upstream natural gas, and the design and construction of renewable energy facilities. These increases were partially offset by the reduction in revenues net of purchased power and fuel expense from the sale of Brandon Shores, H.A. Wagner and C.P. Crane, the generating facilities divested in the fourth quarter of 2012 as a result of the Exelon and Constellation merger. See Note 10—Intangible Assets 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.

Nuclear Fleet Capacity Factor and Production Costs

The following table presents nuclear fleet operating data for 2014, as compared to 2013 and 2012, for the Generation-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, required capital investment, benefits costs associated with labor, insurance, property taxes, unit contingent costs, suspended DOE nuclear waste storage fee (as discussed further in Note 22—Commitments and Contingencies), 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.


	2014			2013			2012
Nuclear fleet capacity factor^(a)		94.3	%		94.1	%		92.7	%
Nuclear fleet production cost per MWh^(a)	$	19.33		$	19.83		$	19.50

(a)	Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. As of April 1, 2014, CENG is included at ownership.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The nuclear fleet capacity factor, which excludes Salem, increased in 2014 compared to 2013. While total days offline are greater in 2014 as compared to 2013, the larger capacity units were online for more days in 2014. Additionally, with the addition of the CENG nuclear facilities there were more days offline in 2014 associated with units where Exelon’s ownership percentage diminishes the impact on capacity factor. For 2014 and 2013, planned refueling outage days totaled 275 and 233, respectively, and non-refueling outage days totaled 92 and 75, respectively. Production cost per MWh was lower in 2014 compared to 2013 due to elimination of the SNF disposal fee in 2014, partially offset by inclusion of the ownership share of CENG.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The nuclear fleet capacity factor, which excludes Salem, increased primarily due to a lower number of planned refueling outage days in 2013, partially offset by a higher number of non-refueling outage days. For 2013 and

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2012, planned refueling outage days totaled 233 and 274, respectively, and non-refueling outage days totaled 75 and 73, respectively. Higher nuclear fuel costs and higher plant operating and maintenance costs, partially offset by higher number of net MWhs generated resulted in a higher production cost per MWh during 2013 as compared to 2012.

Operating and Maintenance Expense

The changes in operating and maintenance expense for 2014 compared to 2013, consisted of the following:


	Increase (Decrease)^(a)
Impairment and related charges of certain generating assets ^(b)	$	506
Labor, other benefits, contracting and materials ^(c)		361
Accretion expense		78
Corporate allocations ^(d)		69
Regulatory fees and assessments		51
Maryland merger commitments		44
Nuclear refueling outage costs, including the co-owned Salem plant ^(e)		54
Increase in asbestos bodily injury reserve		16
Midwest Generation bankruptcy charges		(26	)
ARO update		(29	)
Merger and integration costs		(29	)
Pension and non-pension postretirement benefits expense		(81	)
Other		18

Increase in operating and maintenance expense	$	1,032

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 operating results include CENG’s results of operations on a fully consolidated basis from April 1, 2014 through December 31, 2014.

(b)	Reflects the operating and maintenance expense associated with the impairment of certain generating assets held-for-sale, Upstream assets, and wind generating assets during 2014.

(c)	Reflects an increase of labor, other benefits, contracting and materials costs primarily due to the inclusion of CENG beginning April 1, 2014. Also includes cost of sales of our other business activities that are not allocated to a region.

(d)	Reflects an increased share of corporate allocated costs primarily due to the 2014 CENG integration.

(e)	Reflects the impact of increased nuclear outage days primarily due to the inclusion of CENG beginning April 1, 2014.

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The changes in operating and maintenance expense for 2013 compared to 2012, consisted of the following:


	Increase (Decrease)
Plant retirements and divestitures^(a)	$	(440	)
FERC settlement ^(b)		(195	)
Constellation merger and integration costs		(107	)
Maryland commitments		(35	)
Asbestos bodily injury costs ^(c)		(16	)
Nuclear refueling outage costs, including the co-owned Salem plant ^(d)		(14	)
Corporate allocations ^(e)		(5	)
Labor, other benefits, contracting and materials ^(f)		160
Impairment and related charges of certain generating assets		160
Midwest Generation bankruptcy charges		11
Pension and non-pension postretirement benefits expense		5
Other		(18	)

Decrease in operating and maintenance expense	$	(494	)

(a)	Reflects the operating and maintenance expense associated with the generating assets retired or divested during 2012.

(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 decreased asbestos-related bodily injury expense for 2013 compared to 2012.

(d)	Reflects the impact of decreased planned refueling outages during 2013.

(e)	The decrease in cost allocations during 2013 primarily reflects merger and energy savings for Exelon’s corporate operations and shared service entities, partially offset by the impact of an increased share of corporate allocated costs due to the merger.

(f)	Includes cost of sales of our other business activities that are not allocated to a region.

Depreciation and Amortization

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in depreciation and amortization expense was primarily due to the inclusion of CENG’s results on a fully consolidated basis beginning April 1, 2014 and an increase in ongoing capital expenditures.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in depreciation and amortization expense was primarily a result of higher plant balances due to the addition of Constellation facilities and ongoing capital additions.

Taxes Other Than Income

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase was primarily due to the inclusion of CENG’s results on a fully consolidated basis beginning April 1, 2014.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase was primarily due to the addition of Constellation’s financial results in 2012.

Equity in Earnings (Losses) of Unconsolidated Affiliates

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The year-over-year change in Equity in earnings (losses) of unconsolidated affiliates is primarily the result of the consolidation of CENG’s results of operations beginning April 1, 2014, which were previously accounted for under the equity method of accounting.

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Gain (Loss) on Sales of Assets

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The year-over-year change in Gain (loss) on sales of assets reflects $411 million of gains recorded on the sale of Generation’s ownership interests in Safe Harbor Water Power Corporation, Fore River and West Valley generating stations in 2014. Refer to Note 4—Mergers, Acquisitions and Dispositions in the Combined Notes to Consolidated Financial Statements for additional information.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The year-over-year change in Gain (loss) on sales of assets primarily reflects an $8 million gain recorded on the sale of Maryland Clean Coal in 2013.

Gain on Consolidation and Acquisition of Businesses

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in Gain on consolidation and acquisition of businesses is primarily related to a $261 million gain upon consolidation of CENG resulting from the difference in fair value of CENG’s net assets as of April 1, 2014 and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing transactions between Generation and CENG, and a $28 million bargain-purchase gain related to the lntegrys acquisition.

Interest Expense

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Interest expense for the year ended December 31, 2014 compared to the same period in 2013 remained relatively level.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in interest expense is primarily due to the increase in long-term debt as a result of the merger and increased project financing.

Other, Net

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in Other, net primarily reflects $31 million of favorable tax settlements related to Constellation’s pre-acquisition 2009-2012 tax returns and the net increase in realized and unrealized gains related to the NDT funds of Generation’s Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $67 million and $122 million for the year ended December 31, 2014 and 2013, respectively, related to the contractual elimination of income tax expense associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT funds.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in Other, net primarily reflects $85 million of credit facility termination fees recorded in 2012 and increased net realized and unrealized gains related to the NDT funds of Generation’s Non-Regulatory Agreement Units compared to net realized and unrealized gains in 2012, as described in the table below. Other, net also reflects $122 million and $117 million for the year ended December 31, 2013 and 2012, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT funds.

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The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for 2014, 2013 and 2012:


	2014		2013		2012
Net unrealized gains on decommissioning trust funds	$	134	$	146	$	105
Net realized gains on sale of decommissioning trust funds	$	77	$	24	$	51

Effective Income Tax Rate.

Generation’s effective income tax rates for the years ended December 31, 2014, 2013 and 2012 were 16.9%, 36.7% and 47.3%, respectively. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Results of Operations—ComEd


	2014			2013			Favorable (Unfavorable) 2014 vs. 2013 Variance			2012			Favorable (Unfavorable) 2013 vs. 2012 Variance
Operating revenue	$	4,564		$	4,464		$	100		$	5,443		$	(979	)
Purchased power expense		1,177			1,174			(3	)		2,307			1,133

Revenue net of purchased power expense ^(a)		3,387			3,290			97			3,136			154

Other operating expenses
Operating and maintenance		1,429			1,368			(61	)		1,345			(23	)
Depreciation and amortization		687			669			(18	)		610			(59	)
Taxes other than income		293			299			6			295			(4	)

Total other operating expenses		2,409			2,336			(73	)		2,250			(86	)

Gain on sales of assets		2			—			2			—			—

Operating income		980			954			26			886			68

Other income and (deductions)
Interest expense, net		(321	)		(579	)		258			(307	)		(272	)
Other, net		17			26			(9	)		39			(13	)

Total other income and (deductions)		(304	)		(553	)		249			(268	)		(285	)

Income before income taxes		676			401			275			618			(217	)
Income taxes		268			152			(116	)		239			87

Net income	$	408		$	249		$	159		$	379		$	(130	)

(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, 2014, Compared to Year Ended December 31, 2013. ComEd’s Net income for the year ended December 31, 2014, was higher than the same period in 2013, primarily due

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to the 2013 remeasurement of Exelon’s like-kind exchange tax position, and increased electric distribution and transmission earnings resulting from increased capital investment, partially offset by unfavorable weather.

Year Ended December 31, 2013, Compared to Year Ended December 31, 2012. ComEd’s Net income for the year ended December 31, 2013, was lower than the same period in 2012, primarily due to the remeasurement of Exelon’s like-kind exchange tax position and unfavorable weather, partially offset by increased electric distribution and transmission earnings resulting from increased costs and capital investments and higher allowed ROE. See Note 3—Regulatory Matters and Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements in the 2013 10-K for additional information.

Operating Revenue Net of Purchased Power Expense

There are certain drivers of Operating revenue that are fully offset by their impact on Purchased power expense, such as commodity procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on Revenue net of purchased power expense. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electricity procurement process.

All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenue related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.

The number of retail customers participating in customer choice programs was 2,426,921, 2,630,185 and 1,627,150 at December 31, 2014, 2013 and 2012, respectively, representing 63%, 68% and 43% of total retail customers, respectively. Retail energy purchased from competitive electric generation suppliers represented 80%, 81% and 65% of ComEd’s retail kWh sales for the years ended December 31, 2014, 2013 and 2012, respectively.

The changes in ComEd’s Revenue net of purchased power expense for the year ended 2014 compared to the same period in 2013 consisted of the following:


	Increase
Weather	$	(16	)
Electric distribution revenue		(2	)
Transmission revenue		30
Regulatory required programs		52
Revenue subject to refund		(9	)
Pricing and customer mix		5
Uncollectible accounts recovery, net		41
Other		(4	)

Increase in revenue net of purchased power	$	97

Weather

The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions”

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because these weather conditions result in increased customer usage. Conversely, mild weather reduces demand. For the year ended December 31, 2014, unfavorable weather conditions, primarily during the summer months, reduced Operating revenue net of purchased power expense when compared to prior year.

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, 2014 and 2013 consisted of the following:


	Twelve Months Ended December 31,						% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013		From Normal
Heating Degree-Days		7,027		6,603		6,341		6.4%		10.8%
Cooling Degree-Days		799		933		842		(14.4)%		(5.1)%

Volume

For the year ended December 31, 2014 Revenue net of purchased power expense remained relatively consistent, as compared to the same period in 2013.

Electric Distribution Revenue

EIMA provides for a performance-based formula rate tariff, which requires 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. Under EIMA, distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, allowed ROE, and other billing determinants. In addition, ComEd’s allowed rate of return on common equity is the annual average rate on 30-year treasury notes plus 580 basis points, subject to a collar of plus or minus 50 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on revenue. During the year ended December 31, 2014, distribution revenue decreased $2 million at ComEd, primarily due to lower Operating and maintenance expenses primarily driven by the impacts of certain OPEB plan design changes, partially offset by increased capital investment. See Operating and Maintenance Expense below, ITEM 1. BUSINESS—Commonwealth Edison Company, Note 3—Regulatory Matters and Note 16—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission Revenue

Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing determinants, such as the highest daily peak load from the previous calendar year. During the year ended December 31, 2014, ComEd recorded increased revenue of $30 million due to increased capital investments. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs

This represents the change in Operating revenue collected under approved riders to recover costs incurred for regulatory programs such as ComEd’s energy efficiency and demand response and purchase power administrative costs. The riders are designed to provide full and current cost recovery.

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The costs of these programs are included in Operating and maintenance expense. Refer to the Operating and maintenance expense discussion below for additional information on included programs.

Uncollectible Accounts Recovery, Net

Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. See the Operating and maintenance expense discussion below for additional information on this tariff.

Pricing and Customer Mix

The increase in Revenue net of purchased power as a result of pricing and customer mix is primarily attributable to higher overall effective rates due to decreased usage across all major customer classes and change in customer mix for the years ended December 31, 2014, and 2013, respectively.

Revenue Subject to Refund

ComEd records revenue subject to refund based upon its best estimate of customer collections that may be required to be refunded. For the year ended December 31, 2014, ComEd recorded $9 million of revenue subject to refund associated with Rider AMP. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial statements for additional information.

Other

Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs and recoveries of environmental costs associated with MGP sites, recovery of energy procurement costs, for which an equal and offsetting amount is reflected in Depreciation and amortization expense during the periods presented.

The changes in ComEd’s Revenue net of purchased power expense for 2013 compared to 2012 consisted of the following:


	Increase
Weather	$	(17	)
Volume		(2	)
Electric distribution revenue		168
Discrete impacts of the 2012 distribution rate case order		13
Transmission revenue		14
Regulatory required programs		20
Uncollectible accounts recovery, net		(58	)
Other		16

Increase in revenue net of purchased power	$	154

Weather

For the year ended December 31, 2013, the increase in Revenue net of purchased power expense was offset by unfavorable weather conditions as a result of the mild weather in 2013 compared to the same period in 2012.

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The changes in heating and cooling degree days in ComEd’s service territory for the years ended December 31, 2013 and 2012 consisted of the following:


	Twelve Months Ended December 31,						% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012		From Normal
Heating Degree-Days		6,603		5,065		6,341		30.4%		4.1%
Cooling Degree-Days		933		1,324		842		(29.5)%		10.8%

Volume

Revenue net of purchased power expense decreased as a result of lower delivery volume, exclusive of the effects of weather, for the year ended December 31, 2013, reflecting decreased average usage per residential customer as compared to the same period in 2012.

Electric Distribution Revenue

During the year ended December 31, 2013, ComEd recorded increased revenue of $168 million under EIMA, primarily due to increased capital investments, increased operating expenses, and higher allowed ROE. These amounts exclude the discrete impacts of the 2012 Distribution Rate Case Orders discussed separately below. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Discrete Impacts of the 2012 Distribution Rate Case Orders

On October 3, 2012, the ICC issued its final order related to ComEd’s 2011 formula rate proceeding under EIMA, which reestablished ComEd’s position on the return on its pension asset, resulting in an increase to revenue in 2013. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission Revenue

During the year ended December 31, 2013, ComEd recorded increased revenue during the year ended December 31, 2013 of $14 million, primarily due to increased capital investments and higher operating expenses. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Operating and Maintenance Expense


	Year Ended December 31,				Increase		Year Ended December 31,				Increase
	2014		2013		2014 vs. 2013		2013		2012		2013 vs. 2012
Operating and maintenance expense—baseline	$	1,211	$	1,202	$	9	$	1,202	$	1,199	$	3
Operating and maintenance expense—regulatory required programs^(a)		218		166		52		166		146		20

Total operating and maintenance expense	$	1,429	$	1,368	$	61	$	1,368	$	1,345	$	23

(a)	Operating and maintenance expense for regulatory required programs are recoveries from customers for costs of various legislative and regulatory programs on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenue.

139

The changes in Operating and maintenance expense for year ended December 31, 2014, compared to the same period in 2013 and changes for the year ended December 31, 2013, compared to the same period in 2012, consisted of the following:


	Increase 2014 vs. 2013			Increase 2013 vs. 2012
Baseline
Labor, other benefits, contracting and materials ^(a)	$	56		$	48
Pension and non-pension postretirement benefits expense ^(b)		(85	)		3
Storm-related costs		(11	)		(10	)
Uncollectible accounts expense—provision ^(c)		12			(10	)
Uncollectible accounts expense—recovery, net ^(c)		29			(48	)
Other		8			20

		9			3
Regulatory required programs
Energy efficiency and demand response programs		52			20

Increase in operating and maintenance expense	$	61		$	23

(a)	Reflects decreased contracting costs resulting from new projects associated with EIMA for the years ended December 31, 2014 and 2013. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding EIMA.

(b)	Primarily reflects decreased non-pension costs associated with OPEB plan design changes during 2014. See Note 16—Retirement Benefits of the Combined Notes to the Consolidated Financial Statements for additional information regarding plan changes.

(c)

ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. In 2013, ComEd recorded a net reduction in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery and customers purchasing electricity from competitive electric generation suppliers as a result of municipal aggregation. An equal and offsetting reduction has been recognized in Operating revenue for the periods presented.

Depreciation and Amortization Expense

The changes in Depreciation and amortization expense for 2014 compared to 2013 and 2013 compared to 2012, consisted of the following:


	Increase 2014 vs. 2013			Increase 2013 vs. 2012
Depreciation associated with higher plant balances	$	46		$	22
Amortization of storm-related regulatory assets^(a)		—			4
Amortization of MGP regulatory assets^(b)		(18	)		27
Amortization of other regulatory assets		(3	)		6
Other		(7	)		—

Increase in depreciation and amortization expense	$	18		$	59

(a)	Under EIMA, ComEd is required to recover costs associated with significant storms over a five-year period through the amortization of a regulatory asset.

(b)	An equal and offsetting amount for the amortization expense related to MGP remediation expenditures is reflected in Operating revenue during the periods presented.

Taxes Other Than Income

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxes other than income remained relatively flat for the twelve months ended December 31, 2014, compared to the same periods in 2013.

140

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. Taxes other than income taxes increased primarily due to increased Illinois electricity distribution taxes.

Interest Expense, Net

The changes in Interest expense, net for 2014 compared to 2013 and 2013 compared to 2012 consisted of the following:


	Increase (Decrease) 2014 vs. 2013			Increase (Decrease) 2013 vs. 2012
Interest expense related to uncertain tax positions^(a)	$	(275	)	$	281
Interest expense on debt (including financing trusts)^(b)		16			2
Other		1			(11	)

Increase (decrease) in interest expense, net	$	(258	)	$	272

(a)	Primarily reflects the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

(b)	Primarily reflects interest expense related to the First Mortgage Bonds. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s debt obligations.

Other, Net

The changes in Other, net for 2014 compared to 2013 and 2013 compared to 2012 consisted of the following:


	Increase (Decrease) 2014 vs. 2013			Increase (Decrease) 2013 vs. 2012
Interest income related to uncertain tax positions^(a)	$	—		$	(20	)
AFUDC—Equity		(8	)		—
Other		(1	)		7

Increase (decrease) in Other, net	$	(9	)	$	(13	)

(a)	Primarily reflects a receivable recorded in the fourth quarter of 2012 related to the final 1999-2001 IRS settlement.

141

Effective Income Tax Rate

ComEd’s effective income tax rates for the years ended December 31, 2014, 2013 and 2012, were 39.6%, 37.9% and 38.7%, respectively. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ComEd Electric Operating Statistics and Revenue Detail


Retail Deliveries to customers (in GWhs)	2014		2013		% Change 2014 vs 2013			Weather- Normal % Change			2012		% Change 2013 vs 2012			Weather- Normal % Change
Retail Deliveries^(a)
Residential		27,230		27,800		(2.1	)%		0.3	%		28,528		(2.6	)%		(0.6	)%
Small commercial & industrial		32,146		32,305		(0.5	)%		(0.3	)%		32,534		(0.7	)%		0.2	%
Large commercial & industrial		27,847		27,684		0.6	%		0.7	%		27,643		0.1	%		(0.3	)%
Public authorities & electric railroads		1,358		1,355		0.2	%		(0.7	)%		1,272		6.5	%		4.2	%

Total retail deliveries		88,581		89,144		(0.6	)%		0.2	%		89,977		(0.9	)%		(0.1	)%


	As of December 31,
Number of Electric Customers	2014		2013		2012
Residential		3,502,386		3,480,398		3,455,546
Small commercial & industrial		369,053		367,569		365,357
Large commercial & industrial		1,998		1,984		1,980
Public authorities & electric railroads		4,815		4,853		4,812

Total		3,878,252		3,854,804		3,827,695


Electric Revenue	2014		2013		% Change 2014 vs 2013		2012		% Change 2013 vs 2012
Retail Sales^(a)
Residential	$	2,074	$	2,073		— %	$	3,037		(31.7	)%
Small commercial & industrial		1,335		1,250		6.8%		1,339		(6.6	)%
Large commercial & industrial		434		427		1.6%		395		8.1	%
Public authorities & electric railroads		46		48		(4.2)%		44		9.1	%

Total retail sales		3,889		3,798		2.4%		4,815		(21.1	)%

Other revenue^(b)		675		666		1.4%		628		6.1	%

Total electric revenue	$	4,564	$	4,464		2.2%	$	5,443		(18.0	)%

(a)

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

(b)

Other revenue primarily includes transmission revenue from PJM. Other items include wholesale revenue, rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, recoveries of environmental remediation costs associated with MGP sites, and intercompany revenue.

142

Results of Operations—PECO


	2014			2013			Favorable (unfavorable) 2014 vs. 2013 variance			2012			Favorable (unfavorable) 2013 vs. 2012 variance
Operating revenue	$	3,094		$	3,100		$	(6	)	$	3,186		$	(86	)
Purchased power and fuel		1,261			1,300			39			1,375			75

Revenue net of purchased power and fuel expense ^(a)		1,833			1,800			33			1,811			(11	)

Other operating expenses
Operating and maintenance		866			748			(118	)		809			61
Depreciation and amortization		236			228			(8	)		217			(11	)
Taxes other than income		159			158			(1	)		162			4

Total other operating expenses		1,261			1,134			(127	)		1,188			54

Operating income		572			666			(94	)		623			43

Other income and (deductions)
Interest expense, net		(113	)		(115	)		2			(123	)		8
Other, net		7			6			1			8			(2	)

Total other income and (deductions)		(106	)		(109	)		3			(115	)		6

Income before income taxes		466			557			(91	)		508			49
Income taxes		114			162			48			127			(35	)

Net income		352			395			(43	)		381			14
Preferred security dividends and redemption		—			7			7			4			(3	)

Net income attributable to common shareholder	$	352		$	388		$	(36	)	$	377		$	11

(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 Attributable to Common Shareholder

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The decrease in Net income attributable to common shareholder was driven primarily by an increase in Operating and maintenance expense partially offset by an increase in Operating revenue net of purchase power and fuel expense and a decrease in Income tax expense.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in Net income was driven primarily by lower Operating and maintenance expense partially offset by an increase in income taxes.

143

Operating Revenue Net of Purchased Power and Fuel Expense

Electric and gas revenue and purchased power and fuel expense 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 that 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 revenue net of purchased power and fuel expense.

Electric and gas revenue 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 546,900, 531,500, and 496,500 at December 31, 2014, 2013 and 2012, respectively. Retail deliveries purchased from competitive electric generation suppliers represented 70%, 68%, and 66% of PECO’s retail kWh sales for the years ended December 31, 2014, 2013 and 2012, respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplier was 78,400, 66,400, and 52,700 at December 31, 2014, 2013 and 2012, respectively. Retail deliveries purchased from competitive natural gas suppliers represented 22%, 19%, and 16% of PECO’s mmcf sales for the years ended December 31, 2014, 2013 and 2012, respectively.

The changes in PECO’s Operating revenue net of purchased power and fuel expense for the year ended December 31, 2014 compared to the same period in 2013 consisted of the following:


	Increase
	Electric			Gas			Total
Weather	$	(15	)	$	13		$	(2	)
Volume		2			5			7
Pricing		(1	)		(3	)		(4	)
Regulatory required programs		33			—			33
Other		(1	)		—			(1	)

Total increase	$	18		$	15		$	33

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. Operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable 2014 summer and fourth quarter weather conditions, partially offset by the impact of favorable first quarter 2014 winter weather conditions in PECO’s service territory.

144

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, 2014 compared to the same period in 2013 and normal weather consisted of the following:


	Twelve Months Ended December 31,						% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		4,749		4,474		4,603		6.1	%		3.2%
Cooling Degree-Days		1,311		1,411		1,301		(7.1	)%		0.8%

Volume

The increase in Operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, primarily reflects the impact of moderate economic and customer growth partially offset by energy efficiency initiatives on customer usages for gas and residential electric and a shift in the volume profile across classes from commercial and industrial classes to residential classes for electric.

Pricing

The decrease in gas operating revenue net of fuel expense as a result of pricing is primarily attributable to lower overall effective rates due to increased retail gas usage.

Regulatory Required Programs

This represents the change in operating revenue collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The 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.

The changes in PECO’s operating revenue net of purchased power and fuel expense for the year ended December 31, 2013 compared to the same period in 2012 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Weather	$	6		$	31		$	37
Volume		(3	)		(3	)		(6	)
Pricing		(14	)		2			(12	)
Regulatory required programs		(6	)		—			(6	)
Gross receipts tax		(8	)		—			(8	)
Gas distribution tax repair		—			(8	)		(8	)
Other		(7	)		(1	)		(8	)

Total increase (decrease)	$	(32	)	$	21		$	(11	)

Weather

Operating revenue net of purchased power and fuel expense were higher due to the impact of favorable 2013 winter weather conditions.

145

The changes in heating and cooling degree days in PECO’s service territory for the year ended December 31, 2013 compared to the same period in 2012 and normal weather consisted of the following:


	Twelve Months Ended December 31,						% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		4,474		3,747		4,603		19.4	%		(2.8	)%
Cooling Degree-Days		1,411		1,603		1,301		(12.0	)%		8.5	%

Volume

The decrease in electric revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, reflected the impact of energy efficiency initiatives on customer usages as well as a shift in the volume profile across classes from residential classes to commercial and industrial classes, partially offset by the oil refineries returning to full production in 2013 as well as moderate economic growth. The decrease in gas revenue net of fuel expense related to delivery volume, exclusive of the effects of weather, primarily reflected a decline in residential use per customer.

Pricing

The decrease in electric operating revenue net of purchased power expense as a result of pricing is primarily attributable to lower overall effective rates due to increased usage across all major customer classes.

Regulatory Required Programs

This represents the change in operating revenue 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.

Gross Receipts Tax

GRT is an excise tax on total electric revenue. As a result of decreases in operating revenue compared to 2012, GRT decreased. Equal and offsetting decreases in GRT have been reflected in Taxes other than income.

Gas Distribution Tax Repair

The decrease in gas distribution tax repair reflected the 2012 tax benefit received from prior period gas distribution repairs for the 2011 tax year. There is an equal and offsetting tax benefit in Operating revenue, see Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further explanation.

Other

The decrease in other electric revenue net of purchased power expense compared to the year ended December 31, 2012 reflected a decrease in wholesale transmission revenue earned by PECO due to higher peak loads in the previous years.

146

Operating and Maintenance Expense


	Twelve Months Ended December 31,				Increase		Twelve Months Ended December 31,				(Decrease)
	2014		2013		2014 vs. 2013		2013		2012		2013 vs. 2012
Operating and maintenance expense—baseline	$	761	$	668	$	93	$	668	$	723	$	(55	)
Operating and maintenance expense—regulatory required programs^(a)		105		80	$	25		80		86	$	(6	)

Total operating and maintenance expense	$	866	$	748	$	118	$	748	$	809	$	(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 revenue.

The changes in Operating and maintenance expense for 2014 compared to 2013 and 2013 compared to 2012 consisted of the following:


	Increase (Decrease) 2014 vs. 2013			Increase (Decrease) 2013 vs. 2012
Baseline
Labor, other benefits, contracting and materials	$	12		$	10
Storm-related costs		100	^(a)		(49	)
Pension and non-pension postretirement benefits expense		(5	)		(12	)
Merger and integration costs		(7	)		(8	)
Corporate allocation		5			—
Uncollectible accounts expense		(9	)		—
Other		(3	)		4

		93			(55	)

Regulatory required programs
Smart meter		7			4
Energy efficiency		17			(9	)
Consumer education program		—			(1	)
Other		1			—

		25			(6	)

Increase (decrease) in operating and maintenance expense	$	118		$	(61	)

(a)	Total storm-related costs include approximately $85 million of incremental storm costs, including the February 5, 2014 ice storm and the significant July storms.

Depreciation and Amortization Expense

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in Depreciation and amortization expense, net for 2014, compared to 2013 was primarily due to ongoing capital expenditures and regulatory required programs.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in Depreciation and amortization expense, net for 2013 compared to 2012 was primarily due to ongoing capital expenditures.

147

Taxes Other Than Income

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Taxes other than income remained relatively consistent.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The decrease in Taxes other than income for 2013 compared to 2012 was primarily due to GRT expense slightly offset by sales and use tax.

Interest Expense, Net

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Interest expense, net remained relatively consistent.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The decrease in Interest expense, net for 2013 compared to 2012 was primarily due to refinancing debt at lower interest rates during the second half of 2012.

Other, Net

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Other, net remained relatively consistent.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. Other, net remained relatively consistent.

Effective Income Tax Rate

PECO’s effective income tax rates for the years ended December 31, 2014, 2013 and 2012 were 24.5%, 29.1% and 25.0%, respectively. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the change in effective income tax rates.

PECO Electric Operating Statistics and Revenue Detail


Retail Deliveries to customers (in GWhs)	2014		2013		% Change 2014 vs. 2013			Weather- Normal % Change			2012		% Change 2013 vs. 2012			Weather- Normal % Change
Retail Deliveries ^(a)
Residential		13,222		13,341		(0.9	)%		0.5	%		13,233		0.8	%		—	%
Small commercial & industrial		8,025		8,101		(0.9	)%		—	%		8,063		0.5	%		(1.1	)%
Large commercial & industrial		15,310		15,379		(0.4	)%		(0.1	)%		15,253		0.8	%		1.5	%
Public authorities & electric railroads		937		930		0.8	%		0.8	%		943		(1.4	)%		(1.4	)%

Total electric retail deliveries		37,494		37,751		(0.7	)%		0.1	%		37,492		0.7	%		0.3	%


	As of December 31,
Number of Electric Customers	2014		2013		2012
Residential		1,434,011		1,423,068		1,417,773
Small commercial & industrial		149,149		149,117		148,803
Large commercial & industrial		3,103		3,105		3,111
Public authorities & electric railroads		9,734		9,668		9,660

Total		1,595,997		1,584,958		1,579,347

148


Electric Revenue	2014		2013		% Change 2014 vs. 2013			2012		% Change 2013 vs. 2012
Retail Sales ^(a)
Residential	$	1,555	$	1,592		(2.3	)%	$	1,689		(5.7	)%
Small commercial & industrial		423		433		(2.3	)%		462		(6.3	)%
Large commercial & industrial		217		224		(3.1	)%		232		(3.4	)%
Public authorities & electric railroads		32		30		6.7	%		31		(3.2	)%

Total retail		2,227		2,279		(2.3	)%		2,414		(5.6	)%

Other revenue^(b)		221		221		—	%		226		(2.2	)%

Total electric revenue	$	2,448	$	2,500		(2.1	)%	$	2,640		(5.3	)%

(a)

Reflects delivery volumes and revenue 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 reflect the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenue.

PECO Gas Operating Statistics and Revenue Detail


Deliveries to customers (in mmcf)	2014		2013		% Change 2014 vs. 2013			Weather- Normal % Change			2012		% Change 2013 vs. 2012			Weather- Normal % Change
Retail Deliveries ^(a)
Retail sales		62,734		57,613		8.9	%		2.2	%		49,767		15.8	%		(0.1	)%
Transportation and other		27,208		28,089		(3.1	)%		(1.0	)%		26,687		5.3	%		0.5	%

Total gas deliveries		89,942		85,702		4.9	%		1.2	%		76,454		12.1	%		0.1	%


	As of December 31,
Number of Gas Customers	2014		2013		2012
Residential		462,663		458,356		454,502
Commercial & industrial		42,686		42,174		41,836

Total retail		505,349		500,530		496,338
Transportation		855		909		903

Total		506,204		501,439		497,241


Gas revenue	2014		2013		% Change 2014 vs. 2013			2012		% Change 2013 vs. 2012
Retail Sales ^(a)
Retail sales	$	608	$	562		8.2	%	$	509		10.4	%
Transportation and other		38		38		—	%		37		2.7	%

Total gas revenue	$	646	$	600		7.7	%	$	546		9.9	%

(a)

Reflects delivery volumes and revenue 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 reflect the cost of natural gas.

149

Results of Operations—BGE


	2014			2013			Favorable (unfavorable) 2014 vs. 2013 variance			2012			Favorable (unfavorable) 2013 vs. 2012 variance
Operating revenue	$	3,165		$	3,065		$	100		$	2,735		$	330
Purchased power and fuel expense		1,417			1,421			4			1,369			(52	)

Revenue net of purchased power and fuel expense ^(a)		1,748			1,644			104			1,366			278

Other operating expenses
Operating and maintenance		717			634			(83	)		728			94
Depreciation and amortization		371			348			(23	)		298			(50	)
Taxes other than income		221			213			(8	)		208			(5	)

Total other operating expenses		1,309			1,195			(114	)		1,234			39

Operating income		439			449			(10	)		132			317

Other income and (deductions)
Interest expense, net		(106	)		(122	)		16			(144	)		22
Other, net		18			17			1			23			(6	)

Total other income and (deductions)		(88	)		(105	)		17			(121	)		16

Income before income taxes		351			344			7			11			333
Income taxes		140			134			(6	)		7			(127	)

Net income		211			210			1			4			206
Preference stock dividends		13			13			—			13			—

Net income (loss) attributable to common shareholder	$	198		$	197		$	1		$	(9	)	$	206

(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 (Loss) Attributable to Common Shareholder

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Net income attributable to common shareholder remained relatively consistent primarily due to an increase in Revenue net of purchased power and fuel expense as a result of the December 2013 and 2014 electric and gas distribution rate order issued by the MDPSC offset by increases in Operating and maintenance expense and Depreciation expense.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in Net income was driven primarily by higher distribution rates as a result of the 2012 rate order issued by MDPSC and decreased Revenue net of purchased power and fuel expense in 2012 related to the accrual of the residential customer rate credit provided as a condition of the MDPSC’s approval of Exelon’s merger with Constellation. Additionally, the increase in Net income was also driven by higher Operating and maintenance expenses in 2012, 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 and lower storm restoration costs in 2013.

150

Operating Revenue 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 revenue 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 electric generation supplier affects electric SOS revenue and purchased power expense. The number of customers electing to select a competitive natural gas supplier affects gas cost adjustment revenue and purchased natural gas expense. All BGE customers have the choice to purchase energy from a competitive electric generation supplier. This customer choice of electric generation suppliers 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 electric generation supplier was 364,000, 399,000 and 362,000 at December 31, 2014, 2013 and 2012, respectively, representing 29%, 32% and 29% of total retail customers, respectively. Retail deliveries purchased from competitive electric generation suppliers represented 60%, 61% and 60% of BGE’s retail kWh sales for the years ended December 31, 2014, 2013 and 2012, respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplier was 161,000, 172,000 and 143,000 at December 31, 2014, 2013 and 2012, respectively, representing 25%, 26% and 22% of total retail customers, respectively. Retail deliveries purchased from competitive natural gas suppliers represented 53%, 54% and 56% of BGE’s retail mmcf sales for the years ended December 31, 2014, 2013 and 2012, respectively.

The changes in BGE’s Operating revenue net of purchased power and fuel expense for the year ended December 31, 2014 compared to the same period in 2013 consisted of the following:


	Increase (Decrease)
	Electric			Gas			Total
Distribution rate increases	$	57		$	28		$	85
Commodity margin		(1	)		12			11
Regulatory required programs		13			(1	)		12
Transmission revenue		10			—			10
Other	$	(12	)	$	(2	)	$	(14	)

Total increase	$	67		$	37		$	104

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 revenue 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 revenue per customer, by customer class, regardless of changes in consumption levels. This allows BGE to recognize revenue at MDPSC-approved levels per customer, regardless of what BGE’s actual distribution volumes were for a billing period. Therefore, while this revenue is 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.

151

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, 2014 compared to the same period in 2013 and normal weather consisted of the following:


	Twelve Months Ended December 31,				Normal		% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		5,091		4,744		4,662		7.3	%		9.2	%
Cooling Degree-Days		732		869		876		(15.8	)%		(16.4	)%

Distribution Rate Increases.

The increase in Operating revenue net of purchased power and fuel expense was primarily due to MDPSC rate orders effective December 13, 2013 and December 15, 2014 approving increases to electric and natural gas distribution rates charged to customers. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Commodity Margin.

The increase in Revenue net of purchased power and fuel expense as a result of commodity margin for the year ended December 31, 2014 compared to the same period in 2013 was primarily due the higher gas margins earned due to extreme cold weather during the first quarter of 2014 under BGE’s market-based rate incentive mechanism. See Note 12—Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for further information.

Regulatory Required Programs.

This represents the change in revenue 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 electric revenue during the year ended December 31, 2014 compared to the same period in 2013 was due to the recovery of higher energy efficiency program costs.

Transmission.

The increase in transmission revenue rates for the year ended December 31, 2014 compared to the same period in 2013 was primarily due to the impact of new transmission rates charged to customers that became effective in June 2014. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other.

Other revenue decreased during the year ended December 31, 2014 compared to the same period in 2013. Other revenue, which can vary from period to period, includes miscellaneous revenue such as service application and late payment fees.

152

The changes in BGE’s Revenue net of purchased power and fuel expense for the year ended December 31, 2013 compared to the same period in 2012 consisted of the following:


	Increase (Decrease)
	Electric		Gas		Total
2012 residential customer rate credit	$	82	$	31	$	113
Distribution rate increases		69		24		93
Regulatory required programs		36		6		42
Other		26		4		30

Total increase	$	213	$	65	$	278

The changes in heating and cooling degree days for the twelve months ended 2013 and 2012, consisted of the following:


	Twelve Months Ended December 31,				Normal		% Change
Heating and Cooling Degree-Days^(a)	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		4,744		3,960		4,661		19.8	%		1.8	%
Cooling Degree-Days		869		1,022		864		(15.0	)%		0.6	%

2012 Residential Customer Rate Credit.

The increase in Revenue net of purchased power and fuel expense for the year ended December 31, 2013 compared to the same period in 2012 was due to the residential customer rate credit provided in 2012 as a result of the MDPSC’s order approving Exelon’s merger with Constellation.

Distribution Rate Increases.

The increase in Revenue net of purchased power and fuel expense as a result of distribution rate increases for the year ended December 31, 2013 compared to the same period in 2012 was primarily due to MDPSC rate orders effective February 23, 2013 and December 13, 2013 approving increases to electric and natural gas distribution rates charged to customers. See Note 3—Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for further information.

Regulatory Required Programs.

This represents the change in revenue 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 revenue during the year ended December 31, 2013 compared to the same period in 2012 was due to the recovery of higher energy efficiency programs costs.

Other.

Other revenue increased during the year ended December 31, 2013 compared to the same period in 2012. Other revenue, which can vary from period to period, includes miscellaneous revenue such as service application and late payment fees.

153

Operating and Maintenance Expense

The changes in operating and maintenance expense for 2014 compared to 2013 and 2013 compared to 2012 consisted of the following:


	Increase (Decrease) 2014 vs. 2013		Increase (Decrease) 2013 vs. 2012
Baseline
Labor, other benefits, contracting and materials	$	22	$	20
Pension and non-pension postretirement benefits expense		8		—
Storm-related costs ^(a)		21		(62	)
Uncollectible accounts expense		17		—
Merger transaction costs		5		(21	)
Charitable contributions ^(b)		—		(28	)
Other		10		(3	)

Increase (Decrease) in operating and maintenance expense	$	83	$	(94	)

(a)

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 were 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 were capital costs.

(b)	During the first quarter of 2012, BGE accrued $28 million in charitable contributions as a result of BGE’s merger-related commitments. The charitable contribution accrual and merger costs are not recoverable from BGE’s customers.

Depreciation and Amortization Expense

The changes in depreciation and amortization expense for 2014 compared to 2013 and 2013 compared to 2012 consisted of the following:


	Increase (Decrease) 2014 vs. 2013			Increase (Decrease) 2013 vs. 2012
Depreciation expense ^(a)	$	25		$	18
Regulatory asset amortization		(1	)		31	^(b)
Other		(1	)		1

Increase in depreciation and amortization expense	$	23		$	50

(a)	Depreciation expense increased due to higher plant balances year over year.

(b)	Regulatory asset amortization for the year ended December 31, 2013 compared to the same period in 2012 increased due to higher energy efficiency and demand response programs expenditures year over year.

Taxes Other Than Income

The change in taxes other than income for 2014 compared to 2013 and 2013 compared to 2012 consisted of the following:


	Increase (Decrease) 2014 vs. 2013		Increase (Decrease) 2013 vs. 2012
Property tax	$	2	$	(2	)
Franchise tax		4		7
Other		2		—

Increase in taxes other than income	$	8	$	5

154

Interest Expense, Net

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The decrease in Interest expense, net for 2014 compared to 2013 was primarily due to favorable interest rates in 2014 on long-term debt balances.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The decrease in Interest expense, net in 2013 compared to 2012 was primarily due to interest recorded in 2012 on prior year tax liabilities and lower effective interest rates as a result of the refinancing of debt at a lower interest rate in 2013.

Effective Income Tax Rate

BGE’s effective income tax rates for the years ended December 31, 2014, 2013 and 2012 were 39.9%, 39.0% and 63.6%, respectively. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

BGE Electric Operating Statistics and Revenue Detail


Retail Deliveries to customers (in GWhs)	2014		2013		% Change 2014 vs. 2013			Weather- Normal % Change		2012		% Change 2013 vs. 2012			Weather- Normal % Change
Retail Deliveries ^(a)
Residential		12,974		13,077		(0.8	)%		n.m.		12,719		2.8	%		n.m.
Small commercial & industrial		3,086		3,035		1.7	%		n.m.		2,990		1.5	%		n.m.
Large commercial & industrial		14,191		14,339		(1.0	)%		n.m.		14,956		(4.1	)%		n.m.
Public authorities & electric railroads		311		317		(1.9	)%		n.m.		329		(3.6	)%		n.m.

Total electric deliveries		30,562		30,768		(0.7	)%		n.m.		30,994		(0.7	)%		n.m.


	As of December 31,
Number of Electric Customers	2014		2013		2012
Residential		1,125,369		1,120,431		1,116,233
Small commercial & industrial		112,972		112,850		112,994
Large commercial & industrial		11,730		11,652		11,580
Public authorities & electric railroads		290		292		319

Total		1,250,361		1,245,225		1,241,126


Electric Revenue	2014		2013		% Change 2014 vs. 2013			2012		% Change 2013 vs. 2012
Retail Sales ^(a)
Residential	$	1,404	$	1,404		—	%	$	1,274		10.2	%
Small commercial & industrial		271		257		5.4	%		248		3.6	%
Large commercial & industrial		491		439		11.8	%		393		11.7	%
Public authorities & electric railroads		32		31		3.2	%		30		3.3	%

Total retail		2,198		2,131		3.1	%		1,945		9.6	%

Other revenue		262		274		(4.4	)%		238		15.1	%

Total electric revenue	$	2,460	$	2,405		2.3	%	$	2,183		10.2	%

(a)

Reflects delivery revenue 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.

155

BGE Gas Operating Statistics and Revenue Detail


Deliveries to customers (in mmcf)	2014		2013		% Change 2014 vs. 2013			Weather- Normal % Change		2012		% Change 2013 vs. 2012			Weather- Normal % Change
Retail Deliveries^(d)
Retail sales		99,194		94,020		5.5	%		n.m.		86,946		8.1	%		n.m.
Transportation and other^(e)		9,242		12,210		(24.3	)%		n.m.		15,751		(22.5	)%		n.m.

Total gas deliveries		108,436		106,230		2.1	%		n.m.		102,697		3.4	%		n.m.


	As of December 31,
Number of Gas Customers	2014		2013		2012
Residential		609,626		611,532		610,827
Commercial & industrial		44,200		44,162		44,228

Total		653,826		655,694		655,055


Gas revenue	2014		2013		% Change 2014 vs. 2013			2012		% Change 2013 vs. 2012
Retail Sales ^(d)
Retail sales	$	622	$	592		5.1	%	$	494		19.8	%
Transportation and other^(e)		83		68		22.1	%		58		17.2	%

Total gas revenue	$	705	$	660		6.8	%	$	552		19.6	%

(d)

Reflects delivery revenue 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.

(e)	Transportation and other gas revenue includes off-system revenue of 9,242 mmcfs ($72 million), 12,210 mmcfs ($55 million), and 15,751 mmcfs ($51 million) for the years ended 2014, 2013 and 2012, respectively.

Liquidity and Capital Resources

Exelon’s and Generation’s current year activity presented below includes the activity of CENG, from the integration date effective April 1, 2014 through December 31, 2014. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

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 billion, $0.6 billion and $0.6 billion, respectively. The Registrants’ revolving credit facilities are in place until 2019. In addition, Generation has $0.5 billion in bilateral facilities with banks which have various expirations between October 2015 and January 2017. The Registrants 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.

156

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 13—Debt and Credit Agreements 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—Regulatory Matters and 22—Commitments and Contingencies 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. 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 pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law were applied in 2012 while others took effect in 2013. On August 8, 2014, this funding relief was extended for five years. The estimated impacts of the law are reflected in the projected pension contributions below.

Exelon expects to make qualified pension plan contributions of $447 million to its qualified pension plans in 2015, of which Generation, ComEd, PECO and BGE expect to contribute $230 million, $138 million, $40 million and $1 million, respectively. Exelon’s and Generation’s expected qualified pension plan contributions above include $36 million related to legacy CENG plans that will be funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $15 million in 2015, of which Generation, ComEd, PECO and BGE will make payments of $6 million, $1 million, $1 million, and $1 million respectively. See Note 16—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for the Registrants’ 2014 and 2013 pension contributions.

157

To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase, especially in years 2017 and beyond. Additionally, the contributions above could change if Exelon changes its pension funding strategy.

Unlike qualified pension plans, other postretirement benefit plans are not subject to statutory minimum contribution requirements and certain plans are not funded. Exelon’s management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $37 million in 2015, of which Generation, ComEd, PECO, and BGE expect to contribute $17 million, $2 million, $0 million, and $17 million, respectively. See Note 16—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for the Registrants’ 2014 and 2013 other postretirement benefit contributions.

See the “Contractual Obligations” section 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 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 as of December 31, 2014 may be as much as $810 million, of which approximately $310 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 will increase by a material amount.

•

Exelon, Generation, and ComEd expect to receive tax refunds of approximately $430 million, $190 million, and $260 million, respectively, in 2015. PECO expects to make tax payments of approximately $6 million related to IRS positions settling in 2015.

•

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.

•

On December 19^th, 2014, President Obama signed H.R. 5771, The Tax Increase Prevention Act. The Act included an extension of 50% bonus depreciation for 2014. As a result of the 50% bonus depreciation extension, Exelon, ExGen, ComEd, PECO, and BGE are estimated to generate incremental cash of approximately $600 million, $272 million, $217 million, $53 million, and $46 million, respectively. The resulting cash benefits are expected primarily in 2015. The cash generated is an acceleration of tax benefits that Registrants would have received over the normal depreciable life of the property. Furthermore, the extension of 50% bonus depreciation will result in a decrease to Generation’s Domestic Production Activities Deduction, reducing cash tax benefits and increasing income tax expense by approximately $30 million for 2014. ComEd’s 2014 revenue requirement is expected to decrease by approximately $12 million (after-tax) due to the extension of 50% bonus depreciation.

158

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the years ended December 31, 2014, 2013 and 2012:


	2014 (d)			2013			2014 vs. 2013 Variance			2012 (c)			2013 vs. 2012 Variance
Net income	$	1,820		$	1,729		$	91			1,171		$	558
Add (subtract):
Non-cash operating activities ^(a)		5,884			4,159			1,725			5,588			(1,429	)
Pension and non-pension postretirement benefit contributions		(617	)		(422	)		(195	)		(462	)		40
Income taxes		(143	)		883			(1,026	)		544			339
Changes in working capital and other noncurrent assets and liabilities ^(b)		(1,047	)		(185	)		(862	)		(731	)		546
Option premiums paid, net		38			(36	)		74			(114	)		78
Counterparty collateral received (paid), net		(1,478	)		215			(1,693	)		135			80

Net cash flows provided by operations	$	4,457		$	6,343		$	(1,886	)	$	6,131		$	212

(a)

Represents depreciation, amortization, depletion and accretion, net fair value changes related to derivatives, 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. See note 23 —Supplemental Financial Information for further detail on non-cash operating activity.

(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.

(c)	Exelon’s 2012 activity includes the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012.

(d)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 activity includes CENG on a fully consolidated basis beginning April 1, 2014.

Cash flows provided by operations for the year ended December 31, 2014, 2013 and 2012 by Registrant were as follows:


	2014		2013		2012
Exelon ^(a)(b)	$	4,457	$	6,343	$	6,131
Generation ^(a)(b)		1,826		3,887		3,581
ComEd		1,326		1,218		1,334
PECO		712		747		878
BGE ^(b)		740		561		485

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 activity includes CENG on a fully consolidated basis beginning April 1, 2014.

(b)	Exelon’s and Generation’s 2012 activity 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. BGE’s 2012 activity includes its activity for the twelve months ended December 31, 2012.

159

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, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for 2014, 2013 and 2012 were as follows:

Generation

•

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. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on the exchange or in the OTC markets. During 2014, 2013 and 2012, Generation had net collections (payments) receipts of counterparty cash collateral of $(1,507) million, $162 million and $95 million, respectively. Net collections (payments) each year were primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position. In addition, in 2014 the exchanges increased initial margin rates, which required Generation to post higher amounts of initial margin.

•

During 2014, 2013 and 2012, Generation had net collections (payments) of approximately $38 million, $(36) million and $(114) 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

•

For the year ended December 31, 2014 and 2013, ComEd had a working capital deficit of $263 million and $508 million, respectively. The working capital deficit is primarily attributable to the increase in short-term borrowings in 2014 and an increase in short-term borrowings and short-term debt due within one year in 2013. Cash flows from operating activities are sufficient to meet operating requirements; however, increased capital investment in infrastructure improvements and modernization pursuant to EIMA, transmission upgrades and expansion may require external debt financing or additional capital contributions from parent.

•

During 2014, 2013 and 2012, ComEd’s net payables to Generation for energy purchases related to its supplier forward contract and ICC-approved RFP contracts increased/(decreased) by $5 million, $(16) million and $(15) million, respectively. During 2014, 2013 and 2012 ComEd’s payables to other energy suppliers for energy purchases increased by $27 million, $35 million and $20 million, respectively.

PECO

•

During 2014, 2013 and 2012, PECO’s payables to Generation for energy purchases increased/(decreased) by $(9) million, $(17) million and $17 million, respectively, and payables to other energy suppliers for energy purchases increased/(decreased) by $10 million, $39 million and $(22) million, respectively.

BGE

•

During 2014, 2013 and 2012, BGE’s payables to Generation for energy purchases increased/(decreased) by $13 million, $(4) million and $23 million, respectively, and payables to other energy suppliers for energy purchases increased/(decreased) by $(7) million, $(12) million and $40 million, respectively.

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Cash Flows from Investing Activities

Cash flows used in investing activities for the year ended December 31, 2014, 2013, and 2012 by Registrant were as follows:


	2014			2013			2012
Exelon ^(a)(b)	$	(4,599	)	$	(5,394	)	$	(4,576	)
Generation ^(a)(b)		(1,767	)		(2,916	)		(2,629	)
ComEd		(1,655	)		(1,387	)		(1,212	)
PECO		(649	)		(531	)		(328	)
BGE ^(b)		(622	)		(571	)		(573	)

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 activity includes CENG on a fully consolidated basis beginning April 1, 2014.

(b)	Exelon’s and Generation’s 2012 activity 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. BGE’s 2012 activity includes its activity for the twelve months ended December 31, 2012.

Generation

As a result of consolidating CENG during the second quarter of 2014, Generation recorded $129 million of cash from CENG, reflected in Generation’s cash flows from investing activities above. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for further information.

Generation closed on the sale of its 67% equity interest in the 417 MW Safe Harbor Water Power Corporation hydroelectric facility on the Susquehanna River in Pennsylvania for a purchase price of approximately $615 million during the third quarter of 2014. The proceeds from the sale are reflected in Generation’s cash flows from investing activities above. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for further information.

During the third quarter of 2014, Generation established $65 million in restricted cash as part of the EGTP project financing which is reflected in Generation’s cash flows from investing activities above. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for more information.

Generation closed on the sale of its 41.98% and 31.28% ownership interests in the Keystone and Conemaugh coal-fired power plants and related equity interests in Keystone Fuels, LLC and Conemaugh Fuels, LLC, respectively, for a purchase price of approximately $473 million during the fourth quarter of 2014. The proceeds from the sale are reflected in Generation’s cash flows from investing activities above. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for further information.

During the fourth quarter of 2014, Generation closed on the sale of its fully-owned equity interest in Fore River and West Valley generating stations, for a combined purchase price of approximately $577 million. The proceeds from the sale are reflected in Generation’s cash flows from investing activities above. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for further information.

During the fourth quarter of 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. for a purchase price of $332 million, including net working capital. The acquisition costs from the sale are reflected in Generation’s cash flows from investing activities above. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for further information.

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Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technology. The agreements include a series of scheduled investment commitments, including in-kind services contributions, totaling approximately $167 million through 2018 to fund anticipated planned capital and operating needs of the associated companies.

Generation has executed, or expects to execute, construction and services contracts to build new gas turbine units in Texas and Maryland and a new biomass-fueled cogeneration facility in Georgia. The total estimated expenditures for these projects are approximately $1.8 billion and achievement of commercial operations is expected between 2015 and 2017 for all these projects.

Capital expenditures by Registrant for the year ended December 31, 2014, 2013, and 2012 and projected amounts for 2015 are as follows:


	Projected 2015 ^(a)		2014		2013		2012
Exelon ^(b)(e)(f)	$	7,200	$	6,077	$	5,395	$	5,789
Generation ^(b)(e)(f)		3,625		3,012		2,752		3,554
ComEd ^(c)		2,200		1,689		1,433		1,246
PECO		550		661		537		422
BGE^(e)		700		620		587		582
Other ^(d)		125		95		86		(15	)

(a)	Total projected capital expenditures do not include adjustments for non-cash activity.

(b)	Includes nuclear fuel.

(c)	The projected capital expenditures include $617 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.

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

(e)	Exelon’s and Generation’s 2012 activity 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. BGE’s 2012 activity includes its activity for the twelve months ended December 31, 2012.

(f)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, CENG is included on a fully consolidated basis beginning April 1, 2014.

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

In 2014, Exelon and its affiliates initiated a comprehensive project to ensure corporate-wide compliance with Version 5 of the North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection Standards (CIP V.5) which will become effective on April 1, 2016. Generation, ComEd, PECO and BGE will be incurring incremental capital expenditures in 2014 through 2016 associated with the CIP V.5 compliance implementation project, which are included in projected capital expenditures above.

Generation

Approximately 33% and 7% of the projected 2015 capital expenditures at Generation are for the acquisition of nuclear fuel and investments in renewable energy and natural gas generation, respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.

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ComEd, PECO and BGE

Approximately 85%, 95% and 96% of the projected 2014 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. ComEd’s capital expenditures include smart grid/smart meter technology required under EIMA. PECO’s and BGE’s capital expenditures include investments related to their respective smart meter programs. The remaining amounts are for capital additions to support new business and customer growth. See Notes 3 and 7 of the Combined Notes to Consolidated Financial Statements for additional information.

In 2010, NERC provided guidance to transmission owners that recommends ComEd, PECO, and BGE, perform assessments of their transmission lines. In compliance with this guidance, ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 2015 capital expenditures above reflect capital spending for remediation to be completed in 2017.

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 the year ended December 31, 2014, 2013, and 2012 by Registrant were as follows:


	2014			2013			2012
Exelon^(a)(b)		411			(826	)		(1,085	)
Generation ^(a)(b)		(537	)		(384	)		(777	)
ComEd		359			61			(212	)
PECO		(250	)		(361	)		(382	)
BGE ^(b)		(85	)		(48	)		128

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 activity includes CENG on a fully consolidated basis beginning April 1, 2014.

(b)	Exelon’s and Generation’s 2012 activity 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. BGE’s 2012 activity includes its activity for the twelve months ended December 31, 2012.

Debt.

See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements. Debt activity for 2014, 2013 and 2012 by Registrant was as follows:

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During the year ended December 31, 2014, the following long term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Junior Subordinated Notes ^(a)

2.50%

June 1, 2024

1,150

Used to finance a portion of the acquisition of PHI and for general corporate purposes

Generation

Nuclear Fuel Procurement Contract

3.35%

June 30, 2018

Used for procurement of uranium

Generation

ExGen Renewables I Nonrecourse Debt ^(b)

LIBOR + 4.25%

February 6, 2021

300

Used for general corporate purposes

Generation

ExGen Texas Power Nonrecourse Debt^(b)

LIBOR + 4.75%

September 18, 2021

675

Used for general corporate purposes

Generation

Energy Efficiency Project Financing

4.12%

December 31, 2015

Funding to install energy conservation measures in Washington, DC

Generation

AVSR DOE Nonrecourse Debt ^(b)

2.78 - 3.14%

January 5, 2037

126

Used for Antelope Valley solar development

Generation

Nuclear Fuel Procurement Contract

3.25%

June 30, 2018

Used for procurement of uranium

ComEd

First Mortgage Bonds Series 115

2.15%

January 15, 2019

300

Used to refinance maturing mortgage bonds and general corporate purposes

ComEd

First Mortgage Bonds Series 116

4.70%

January 15, 2044

350

Used to refinance maturing mortgage bonds and general corporate purposes

ComEd

First Mortgage Bonds Series 117

3.10%

November 1, 2024

250

Used to repay commercial paper and general corporate purposes

PECO

First and Refunding Mortgage Bonds

4.15%

October 1, 2044

300

Used to repay at maturity first and refunding mortgage bonds due October 1, 2014, and general corporate purposes

(a)	See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of the Junior Subordinated Notes and related forward equity purchase contract, which are expected to be remarketed in 2017.

(b)	See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

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On January 13, 2015, Generation issued $750 million in aggregate principal amount of Senior Notes. The Senior Notes carry an annual interest rate of 2.950%, payable semi-annually, commencing July 15, 2015 and due January 15, 2020. The proceeds of the Senior Notes will be used to fund the optional redemption of Exelon’s $550 million, 4.550% Senior Notes due June 15, 2015, expected to occur on February 17, 2015, and for general corporate purposes. In addition to the issuance, Exelon terminated floating-to-fixed interest rate swaps that had been designated as cash flow hedges. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments at this time are probable not to occur. As a result Exelon will reclassify $26 million of deferred losses in AOCI to Other, net in the first quarter of 2015.

165

During the year ended December 31, 2013, the following long term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

CEU Upstream Nonrecourse Debt

2.210 - 2.440%

July 22, 2016

Used to fund Upstream gas activities

Generation

AVSR DOE Nonrecourse Debt

2.535 - 3.353%

January 5, 2037

227

Used for Antelope Valley solar development

Generation

Social Security Administration Project Financing

2.93%

February 18, 2015

Used to install conservation measures for the Social Security Administration Headquarters facility in Maryland

Generation

Energy Efficiency Project Financing

4.40%

August 31, 2014

Used for funding to install energy conservation measures in Beckley, West Virginia

Generation

Continental Wind Nonrecourse Debt

6.00%

February 28, 2033

613

Used for general corporate purposes

ComEd

First Mortgage Bonds, Series 114

4.60%

August 15, 2043

350

Used to repay outstanding commercial paper obligations and for general corporate purposes

PECO

First and Refunding Mortgage Bonds due

1.20%

October 15, 2016

300

Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes

PECO

First and Refunding Mortgage Bonds

4.80%

October 15, 2043

250

Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes

BGE

Notes

3.35%

July 1, 2023

300

Used to partially refinance Notes due July 1, 2013 and for general corporate purposes

166

During the year ended December 31, 2012, the following long term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

CEU Upstream Nonrecourse Debt

Variable Rate

July 16, 2016

Used to fund Upstream gas activities

Generation

AVSR DOE Nonrecourse Debt

Fixed Rate

January 5, 2037

220

Used for Antelope Valley solar development

Generation

Senior Notes

4.25%

June 15, 2022

523

Used for general corporate purposes and issued in connection with the Exchange Offer

Generation

Senior Notes

5.60%

June 15, 2042

788

Used for general corporate purposes and issued in connection with the Exchange Offer

Generation

Constellation Solar Horizons Nonrecourse Debt

2.50%

June 7, 2030

Used for funding for Maryland solar development

ComEd

First Mortgage Bonds, Series 113

3.80%

October 1, 2042

350

Used to repay outstanding commercial paper obligations and for general corporate purposes

PECO

First and Refunding Mortgage Bonds

2.38%

September 15, 2022

350

Used to pay at maturity First Mortgage Bonds due October 1, 2012 and for general corporate purposes

BGE

Notes

2.80%

August 15, 2022

250

Used to repay total outstanding commercial paper obligations and for general corporate purposes

167

During the year ended December 31, 2014, the following long term debt was retired and/or redeemed:


Company	Type	Interest Rate	Maturity	Amount
Generation	2003 Senior Notes	5.35%	January 15, 2014	$	500

Generation	Pollution Control Loan	4.10%	July 1, 2014		20

Generation	Continental Wind Nonrecourse Debt ^(a)	6.00%	February 28, 2033		20

Generation	Kennett Square Capital Lease	7.83%	September 20, 2020		3

Generation	ExGen Renewables I Nonrecourse Debt ^(a)	LIBOR + 4.25%	February 6, 2021		18

Generation	ExGen Texas Power Nonrecourse Debt ^(a)	LIBOR + 4.75%	September 18, 2021		2

Generation	AVSR DOE Nonrecourse Debt ^(a)	2.33% - 3.55%	January 5, 2037		15

Generation	Constellation Solar Horizons Nonrecourse Debt ^(a)	2.56%	September 7, 2030		2

Generation	Sacramento PV Energy Nonrecourse Debt ^(a)	2.56%	December 31, 2030		2

Generation	Energy Efficiency Project Financing	4.12%	December 31, 2015		12

ComEd	Mortgage Bonds Series 110	1.63%	January 15, 2014		600

ComEd	Pollution Control Series 1994C	5.85%	January 15, 2014		17

PECO	First and Refunding Mortgage Bonds	5.00%	October 1, 2014		250

BGE	Rate Stabilization Bonds	5.72%	April 1, 2017		35

BGE	Rate Stabilization Bonds	5.72%	October 1, 2014		35

(a)	See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

168

During the year ended December 31, 2013, the following long term debt was retired and/or redeemed:


Company	Type	Interest Rate	Maturity	Amount
Generation	Kennett Square Capital Lease	7.83%	September 1, 2020	$	3

Generation	Solar Revolver Nonrecourse Debt	Variable Rate	July 7, 2014		113

Generation	Constellation Solar Horizons Nonrecourse Debt	2.56%	September 7, 2030		2

Generation	Sacramento Energy Nonrecourse Debt	2.68%	December 31, 2030		2

Generation ^(a)	Series A Junior Subordinated Debentures	8.63%	June 15, 2063		450

Generation	Energy Efficiency Project Financing	4.40%	August 31, 2014		9

ComEd	First Mortgage Bonds, Series 92	7.63%	April 15, 2013		125

ComEd	First Mortgage Bonds, Series 94	7.50%	July 1, 2013		127

PECO	First and Refunding Mortgage Bonds	5.60%	October 15, 2013		300

BGE	Rate Stabilization Bonds	5.72%	April 1, 2017		67

BGE	Notes	6.13%	July 1, 2013		400

(a)

Represents debt obligations assumed by Exelon as part of the merger on March 12, 2012 that became callable at face value on June 15, 2013. 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 as of December 31, 2012 included in long-term debt to affiliate on Generation’s Consolidated Balance Sheets and notes receivable from affiliates at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. The third-party debt obligations were reported in Long-term Debt on Exelon’s Consolidated Balance Sheets as of December 31, 2012. The debentures were redeemed and the intercompany loan agreements repaid on June 15, 2013.

169

During the year ended December 31, 2012, the following long term debt was retired and/or redeemed:


Company	Type	Interest Rate	Maturity	Amount
Exelon	Fixed rate Medium Term Notes	7.30%	June 1, 2012	$	2

Exelon	Fixed rate Senior Notes	7.60%	April 1, 2032		442

Generation	Kennett Square Capital Lease	7.83%	September 20, 2020		2

Generation	3-year term rate Armstrong Co. 2009 A, Pollution Control Notes	5.00%	December 1, 2042		46

Generation	CEU Upstream Nonrecourse Debt	Variable Rate	July 16, 2016		89

Generation	Solar Revolver Nonrecourse Debt	Variable Rate	July 7, 2014		17

Generation	MEDCO Tax-Exempt Bonds	Variable Rate	April 1, 2024		75

Generation	Sacramento PV Energy Nonrecourse Debt	Variable Rate	March 12, 2012		2

ComEd	First Mortgage Bonds, Series 98	6.15%	March 15, 2012		450

PECO	First and Refunding Mortgage Bonds	4.75%	October 1, 2012		225

PECO	First and Refunding Mortgage Bonds	4.00%	December 1, 2012		150

BGE	Rate Stabilization Bonds	5.72%	April 1, 2016		8

BGE	Rate Stabilization Bonds	5.47%	October 1, 2012		55

BGE	Medium Term Notes	Variable Rate	June 15, 2012		110

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 for the year ended December 31, 2014, 2013 and 2012 by Registrant were as follows:


	2014		2013		2012
Exelon^(a)	$	1,486	$	1,249		1,716
Generation^(a)		1,066		625		1,626
ComEd		307		220		105
PECO		320		333		347
BGE^(b)		13		13		13

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 activity includes CENG on a fully consolidated basis beginning April 1, 2014. As such, includes $421 million of distributions to EDF in 2014.

(b)	Relates to dividends paid on BGE’s preference stock.

First Quarter 2014 Dividend

On January 28, 2014, the Exelon Board of Directors declared a first quarter 2014 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on March 10, 2014, to shareholders of record of Exelon at the end of the day on February 14, 2014.

170

Second Quarter 2014 Dividend

On May 6, 2014, the Exelon Board of Directors declared a second quarter 2014 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on June 10, 2014, to shareholders of record of Exelon at the end of the day on May 16, 2014.

Third Quarter 2014 Dividend

On July 29, 2014, the Exelon Board of Directors declared a third quarter 2014 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on September 10, 2014 to shareholders of record of Exelon at the end of the day on August 15, 2014.

Fourth Quarter 2014 Dividend

On October 21, 2014, the Exelon Board of Directors declared a fourth quarter 2014 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on December 10, 2014 to shareholders of record of Exelon at the end of the day on November 14, 2014.

First Quarter 2015 Dividend

On January 27, 2015, the Exelon Board of Directors declared a first quarter 2015 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on March 10, 2015, to shareholders of record of Exelon at the end of the day on February 13, 2015.

Short-Term Borrowings. Short-term borrowings incurred (repaid) during 2014, 2013 and 2012 by Registrant were as follows:


	2014			2013		2012
Generation ^(a)	$	17		$	13	$	(52	)
ComEd		120			184		—
BGE		(15	)		135		—
Other^(b)		—			—		(145	)

Exelon ^(a)	$	122		$	332	$	(197	)

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 activity includes CENG on a fully consolidated basis beginning April 1, 2014.

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

Retirement of Long-Term Debt to Financing Affiliates. There were no retirements of long-term debt to financing affiliates during 2014, 2013 and 2012 by the Registrants.

Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during 2014, 2013 and 2012 by Registrant were as follows:


	2014		2013		2012
Generation	$	53	$	26	$	48
ComEd^(a)		278		176		11
PECO		24		27		9
BGE		—		—		66

(a)	In 2014 and 2013, represents indemnification from Exelon in relation to the like-kind exchange transaction. For 2014 , also represents contributions from Exelon to support expanded capital programs.

171

Distributions to Noncontrolling Interests of Consolidated VIE. On April 1, 2014, Generation loaned $400 million to CENG, the proceeds of which were used to make a distribution to EDFI of $400 million. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for additional information on the integration of CENG.

Other. For the year ended December 31, 2014, other financing activities primarily consisted of financing costs associated with the acquisition of PHI, other project financing and various debt issuance costs. See notes 4, 13, and 19 of the Combined Notes to Consolidated Financial Statements’ for additional information.

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 $8.5 billion in aggregate total commitments of which $7.3 billion was available as of December 31, 2014, and of which no financial institution has more than 8% of the aggregate commitments for Exelon, Generation, ComEd, PECO and BGE. The Registrants had access to the commercial paper market during 2014 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 flow 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, 2014, it would have been required to provide incremental collateral of $2.4 billion 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, which is well within its current available credit facility capacities of $4.6 billion. If ComEd lost its investment grade credit ratings as of December 31, 2014, it would have been required to provide incremental collateral of $14 million, which is well within its current available credit facility capacity of $998 million. If PECO lost its investment grade credit rating as of December 31, 2014 it would not be required to provide collateral pursuant to PJM’s credit policy and could have been required to provide collateral of $36 million related to its natural gas procurement contracts, which, in the aggregate, are well within PECO’s current available credit facility capacity of $599 million. If BGE lost its investment grade credit rating as of December 31, 2014 it would have been required to provide collateral of $2 million pursuant to PJM’s credit policy and could have been required to provide collateral of $79 million related to its natural gas procurement contracts, which, in the aggregate, are well within BGE’s current available credit facility capacity of $600 million.

Exelon Credit Facilities

See Note 13—Debt and Credit Agreements 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, 2014, the capital structures of the Registrants consisted of the following:


	Exelon			Generation			ComEd			PECO			BGE
Long-term debt		46	%		30	%		42	%		41	%		36	%
Long-term debt to affiliates^(a)		1	%		7	%		1	%		3	%		5	%
Common equity		52	%		—			55	%		56	%		53	%
Member’s equity		—			63	%		—			—			—
Preference Stock		—			—			—			—			4	%
Commercial paper and notes payable		1	%		—			2	%		—			2	%

(a)

Includes approximately $648 million, $206 million, $184 million and $258 million owed to unconsolidated affiliates of Exelon, ComEd, PECO and BGE respectively. 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—Variable Interest Entities 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. Maximum amounts contributed to and borrowed from the money pool by participants during the year ended December 31, 2014, in addition to the net contribution or borrowing as of December 31, 2014, are presented in the following table:


	Maximum Contributed		Maximum Borrowed		December 31, 2014 Contributed (Borrowed)
Generation	$	84	$	573	$	—
PECO		129		35		—
BSC		15		360		(261	)
Exelon Corporate		780		N/A		261

Investments in Nuclear Decommissioning Trust Funds. Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’s investment policies establishes limits on the concentration of holdings in any one company and also in any one industry. See Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.

Shelf Registration Statements. The Registrants maintain a combined shelf registration statement unlimited in amount, with the SEC. The ability of each Registrant to sell securities off the 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. As of December 31, 2014, ComEd had $702 million available in long-term debt refinancing authority and

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$943 million available in new money long-term debt financing authority from the ICC. During the fourth quarter of 2014, ComEd requested an extension of the expiration date of the refinancing authority from the ICC. In January 2015, the ICC approved the extension of the refinancing authority, which now expires on February 27, 2017. As of December 31, 2014, PECO had $1.1 billion available in long-term debt financing authority from the PAPUC. As of December 31, 2014, BGE had $1.4 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, 2014, ComEd, PECO had BGE had short-term financing authority from FERC, which expires on December 31, 2015, of $2.5 billion, $2.5 billion and $700 million, respectively. Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. See Note 3—Regulatory Matters 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, 2014, Exelon had retained earnings of $10,910 million, including Generation’s undistributed earnings of $3,803 million, ComEd’s retained earnings of $851 million consisting of retained earnings appropriated for future dividends of $2,490 million partially offset by $1,639 million of unappropriated retained deficit, PECO’s retained earnings of $681 million and BGE’s retained earnings $1,203 million. See Note 22—Commitments and Contingencies 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, 2014 under existing contractual obligations, including payments due by period. See Note 22—Commitments and Contingencies 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		2015		2016- 2017		2018- 2019		Due 2020 and beyond		All Other
Long-term debt ^(a)	$	21,372	$	1,736	$	3,661	$	2,387	$	13,588	$	—
Interest payments on long-term debt ^(b)		13,105		922		1,755		1,435		8,993		—
Liability and interest for uncertain tax positions ^(c)		779		—		—		—		—		779
Capital leases		32		3		8		9		12		—
Operating leases ^(d)		1,158		99		204		156		699		—
Purchase power obligations ^(e)		2,084		590		884		295		315		—
Fuel purchase agreements ^(f)		10,020		1,661		2,555		2,048		3,756		—
Electric supply procurement ^(f)		1,510		1,057		453		—		—		—
AEC purchase commitments ^(f)		8		1		2		2		3		—
Curtailment services commitments ^(f)		115		40		63		12		—		—
Long-term renewable energy and REC commitments ^(g)		1,516		75		152		162		1,127		—
Other purchase obligations ^(h)		894		336		408		66		84		—
Construction commitments ⁽ⁱ⁾		1,143		43		1,100		—		—		—
PJM regional transmission expansion commitments ^(j)		786		259		414		113		—		—
Spent nuclear fuel obligation ^(k)		1,021		—		—		—		1,021		—
Pension minimum funding requirement ^(l)		1,892		447		782		424		239		—

Total contractual obligations	$	57,435	$	7,269	$	12,441	$	7,109	$	29,837	$	779

(a)	Includes $648 million due after 2020 to ComEd, PECO and BGE financing trusts.

(b)

Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2014 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, 2014. Includes estimated interest payments due to ComEd, PECO and BGE financing trusts.

(c)

As of December 31, 2014, Exelon’s liability for uncertain tax positions and related interest payable was $469 million and $310 million, respectively. 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 14—Income Taxes 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, 2014, including those related to CENG. Expected payments include certain fixed capacity charges which may be reduced based 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—Regulatory Matters and 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

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(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 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for electric and gas purchase commitments.

(g)

Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(h)	Represents commitments for services, materials, information technology, smart meter installation and commitments related to assets-held-for-sale. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(i)	Represents commitments for Generation’s ongoing investments in renewables development, new natural gas and biomass generation construction. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

(j)

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—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(k)	See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding spent nuclear fuel obligations.

(l)

These amounts represent Exelon’s expected contributions to its qualified pension plans. For Exelon’s largest qualified pension plan, the projected contributions reflect a funding strategy of contributing the greater of $250 million until the plan is fully funded on an accumulated benefit obligation basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status thereafter. The remaining qualified pension plans’ contributions are generally based on the estimated minimum pension contributions required under ERISA and the Pension Protection Act of 2006, as well as contributions necessary 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 2020 are not included. See Note 16—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding estimated future pension benefit payments.

Generation


			Payment due within
	Total		2015		2016- 2017		2018- 2019		Due 2020 and beyond		All Other
Long-term debt	$	8,110	$	601	$	701	$	747	$	6,061	$	—
Interest payments on long-term debt^(a)		5,392		391		772		683		3,546		—
Liability and interest for uncertain tax benefits ^(b)		58		—		—		—		—		58
Capital leases		24		3		8		9		4		—
Operating leases^(c)		899		51		120		100		628		—
Purchase power obligations^(d)		2,084		590		884		295		315		—
Fuel purchase agreements^(e)		8,981		1,404		2,243		1,889		3,445		—
Other purchase obligations ^(f)		396		163		109		54		70		—
Construction commitments ^(g)		1,143		43		1,100		—		—		—
Spent nuclear fuel obligation ^(h)		1,021		—		—		—		1,021		—

Total contractual obligations	$	28,108	$	3,246	$	5,937	$	3,777	$	15,090	$	58

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2014 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, 2014.

(b)

As of December 31, 2014, Generation’s liability for uncertain tax positions and related interest receivable was $98 million and $40 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, 2014. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

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(e)	See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding fuel purchase agreements.

(f)	Represents commitments for services, materials, information technology and commitments related to assets-held-for-sale. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(g)	See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding Generation’s ongoing investments in renewables development, new natural gas and biomass generation construction.

(h)	See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding spent nuclear fuel obligations.

ComEd


			Payment due within
	Total		2015		2016- 2017		2018- 2019		Due 2020 and beyond		All Other
Long-term debt^(a)	$	6,175	$	260	$	1,090	$	1,140	$	3,685	$	—
Interest payments on long-term debt^(b)		3,882		292		536		379		2,675		—
Liability and interest for uncertain tax positions^(c)		385		—		—		—		—		385
Capital leases		8		—		—		—		8		—
Operating leases		45		14		21		8		2		—
Electric supply procurement		620		329		291		—		—		—
Long-term renewable energy and associated REC commitments^(d)		1,517		75		153		162		1,127		—
Other purchase obligations ^(e)		148		63		78		2		5		—
PJM regional transmission expansion commitments^(f)		335		150		177		8		—		—

Total contractual obligations	$	13,115	$	1,183	$	2,346	$	1,699	$	7,502	$	385

(a)	Includes $206 million due after 2020 to a ComEd financing trust.

(b)

(c)

As of December 31, 2014, ComEd’s liability for uncertain tax positions and related interest payable was $182 million and $203 million respectively. ComEd was unable to reasonably estimate the timing of liability and interest payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions.

(d)

(e)	Represents commitments for services, materials, information technology, and smart meter installation. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(f)

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—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

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PECO


			Payment due within
	Total		2015		2016- 2017		2018- 2019		Due 2020 and beyond		All Other
Long-term debt^(a)	$	2,434	$	—	$	300	$	500	$	1,634	$	—
Interest payments on long-term debt^(b)		1,773		107		210		158		1,298		—
Operating leases		14		3		6		5		—		—
Fuel purchase agreements^(c)		428		146		163		48		71		—
Electric supply procurement^(c)		609		527		82		—		—		—
AEC purchase commitments^(c)		13		2		4		4		3		—
Other purchase obligations ^(d)		7		3		4		—		—		—
PJM regional transmission expansion commitments^(e)		100		32		56		12		—		—

Total contractual obligations	$	5,378	$	820	$	825	$	727	$	3,006	$	—

(a)	Includes $184 million due after 2020 to PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2013 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 purchase AECs. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(d)	Represents commitments for services, materials, information technology, and smart meter installation. See Note 22—Commitments and Contingencies 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—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

BGE


			Payment due within
	Total		2015		2016- 2017		2018- 2019		Due 2020 and beyond		All Other
Long-term debt^(a)	$	2,203	$	75	$	420	$	—	$	1,708	$	—
Interest payments on long-term debt^(b)		1,477		104		181		159		1,033		—
Liability and interest for uncertain tax positions ^(c)		1		—		—		—		—		1
Operating leases		77		13		21		16		27		—
Fuel purchase agreements^(d)		611		111		149		111		240		—
Electric supply procurement^(d)		1,315		779		536		—		—		—
Curtailment services commitments^(d)		115		40		63		12		—		—
Other purchase obligations ^(e)		343		107		217		10		9		—
PJM regional transmission expansion commitments^(f)		351		77		181		93		—		—

Total contractual obligations	$	6,493	$	1,306	$	1,768	$	401	$	3,017	$	1

(a)	Includes $258 million due after 2020 to the BGE financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2014 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(c)	As of December 31, 2014, BGE’s liability for interest payable was $1 million. BGE 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)	Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

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(e)	Represents commitments for services, materials, information technology, and smart meter installation. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(f)

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—Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

See Note 22—Commitments and Contingencies 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 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.

•

long-term debt, see Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.

•

liabilities related to uncertain tax positions, see Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements.

•

capital lease obligations, see Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.

•

operating leases, energy commitments, fuel purchase agreements, construction commitments and rate relief commitments, see Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•

the nuclear decommissioning and SNF obligations, see Notes 15—Asset Retirement Obligations and 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•

regulatory commitments, see Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

•

variable interest entities, see Note 2—Variable Interest Entities of the Combined Notes to Consolidated Financial Statements.

•

nuclear insurance, see Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•

new accounting pronouncements, see Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements.

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ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk 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 non-derivative contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2015 through 2017.

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, 2014, the percentage of expected generation hedged for the major reportable segments was 93%-96%, 61%-64% and 31%-34% for 2015, 2016 and 2017, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation (which reflects the divestiture impact of Quail Run). Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. 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. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for more detail regarding divestitures.

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, 2014, market conditions and hedged position would be a decrease in pre-tax net income of approximately $10 million, $350 million and $670 million, respectively, for 2015, 2016 and 2017. Power price sensitivities are derived by

180

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 10,571 GWh, 8,762 GWh, and 12,958 GWh for the years ended December 31, 2014, 2013 and 2012 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, 2014, resulted in pre-tax gains of $42 million due to net mark-to-market losses of $26 million and realized gains of $68 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 $0.4 million of exposure during the year. Generation has not segregated proprietary trading activity within the following discussion 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, 2014 of $7,468 million.

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 50% of Generation’s uranium concentrate requirements from 2015 through 2019 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 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.

ComEd

The financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby ensuring that ComEd would be entitled to receive full cost recovery in rates. The change in fair value each period was recorded by ComEd with an offset to a regulatory asset or liability. This financial swap contract between Generation and ComEd expired on May 31, 2013. All realized impacts have been included in Generation’s and ComEd’s results of operations.

ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable

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energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments 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—Regulatory Matters of the Combined Notes to the Consolidated Financial Statements. PECO has certain full requirements contracts and block contracts, which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. 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 12—Derivative Financial Instruments 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 and as a result, are accounted for on an accrual basis of accounting. 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.

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 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

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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, and ComEd’s commodity mark-to-market net asset or liability balance sheet position from January 1, 2013 to December 31, 2014. 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 and does not segregate proprietary trading activity. See Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2014 and December 31, 2013.


	Generation			ComEd			Intercompany Eliminations^(b)			Exelon
Total mark-to-market energy contract net assets (liabilities) at January 1, 2013 ^(a)	$	1,505		$	(293	)	$	—		$	1,212
Total change in fair value during 2013 of contracts recorded in result of operations		444			—			(6	)		438
Reclassification to realized at settlement of contracts recorded in results of operations		25			—			13			38
Reclassification to realized at settlement from accumulated OCI ^(c)		(683	)		—			219			(464	)
Changes in fair value—energy derivatives ^(d)		—			100			(226	)		(126	)
Changes in allocated collateral		(175	)		—			—			(175	)
Changes in net option premium paid/(received)		36			—			—			36
Option premium amortization		(104	)		—			—			(104	)
Other balance sheet reclassifications		(1	)		—			—			(1	)

Total mark-to-market energy contract net assets (liabilities) at December 31, 2013 ^(a)		1,047		$	(193	)	$	—			854
Contracts acquired at merger date ^(e)		128									128
Total change in fair value during 2014 of contracts recorded in result of operations		(608	)		—			—			(608	)
Reclassification to realized at settlement of contracts recorded in results of operations		(21	)		—			—			(21	)
Reclassification to realized at settlement from accumulated OCI		(195	)		—			—			(195	)
Changes in fair value—energy derivatives ^(d)		—			(14	)		—			(14	)
Changes in allocated collateral		1,503			—			—			1,503
Changes in net option premium paid/(received)		(38	)		—			—			(38	)
Option premium amortization		(122	)		—			—			(122	)
Other balance sheet reclassifications		18			—			—			18

Total mark-to-market energy contract net assets (liabilities) at December 31, 2014 ^(a)	$	1,712		$	(207	)	$	—		$	1,505

(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)	Amounts related to the five-year financial swap between Generation and ComEd.

(c)	For Generation, includes $219 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 year ended December 31, 2013.

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(d)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2014 and 2013, ComEd recorded a regulatory liability of $207 million and $193 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. As of December 31, 2013, this includes $11 million of decreases in fair value and $215 million for reclassifications from regulatory assets to recognize cost in purchase power expense due to settlements of ComEd’s five-year financial swap with Generation. As of December 31, 2014 and 2013 ComEd also recorded $13 million and $133 million, respectively, of increases in fair value, and $1 million and $7 million, respectively, of realized losses due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.

(e)	Includes $81 million of fair value from contracts acquired and $47 million of cash collateral as a result of the Integrys acquisition.

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 11—Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

Exelon


	Maturities Within																	Total Fair Value
	2015			2016			2017		2018			2019			2020 and Beyond			Total Fair Value
Normal Operations, Commodity derivative contracts ^(a)(b):
Actively quoted prices (Level 1)	$	(118	)	$	(5	)	$	3	$	(10	)	$	(5	)	$	1		$	(134	)
Prices provided by external sources (Level 2)		522			244			21		7			—			2			796
Prices based on model or other valuation methods (Level 3)^(c)		625			217			140		(21	)		(21	)		(97	)		843

Total	$	1,029		$	456		$	164	$	(24	)	$	(26	)	$	(94	)	$	1,505

(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that 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 $1,406 million at December 31, 2014.

(c)	Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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Generation


	Maturities Within																Total Fair Value
	2015			2016			2017		2018			2019			2020 and Beyond		Total Fair Value
Normal Operations, Commodity derivative contracts ^(a)(b):
Actively quoted prices (Level 1)	$	(118	)	$	(5	)	$	3	$	(10	)	$	(5	)	$	1	$	(134	)
Prices provided by external sources (Level 2)		522			244			21		7			—			2		796
Prices based on model or other valuation methods (Level 3)		645			236			157		(4	)		(4	)		20		1,050

Total	$	1,049		$	475		$	181	$	(7	)	$	(9	)	$	23	$	1,712

(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the 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 $1,406 million at December 31, 2014.

ComEd


	Maturities Within																		Fair Value
	2015			2016			2017			2018			2019			2020 and Beyond			Fair Value
Prices based on model or other valuation methods (Level 3) ^(a)	$	(20	)	$	(19	)	$	(17	)	$	(17	)	$	(17	)	$	(117	)	$	(207	)

(a)	Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Credit Risk, Collateral, and Contingent Related Features (Exelon, Generation, ComEd, PECO and BGE)

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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, 2014. 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 exclude credit risk exposure from individual retail customers, uranium procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, and Nodal commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $43 million, $29 million and $40 million, respectively. See Note 25—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.


Rating as of December 31, 2014	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	$	1,629	$	62	$	1,567		1	$	452
Non-investment grade		49		19		30		—		—
No external ratings
Internally rated—investment grade		479		—		479		—		—
Internally rated—non-investment grade		60		4		56		—		—

Total	$	2,217	$	85	$	2,132		1	$	452


	Maturity of Credit Risk Exposure
Rating as of December 31, 2014	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	1,196	$	379	$	54	$	1,629
Non-investment grade		35		11		3		49
No external ratings
Internally rated—investment grade		388		90		1		479
Internally rated—non-investment grade		60		—		—		60

Total	$	1,679	$	480	$	58	$	2,217


Net Credit Exposure by Type of Counterparty	As of December 31, 2014
Financial institutions	$	295
Investor-owned utilities, marketers, power producers		958
Energy cooperatives and municipalities		862
Other		17

Total	$	2,132

(a)	As of December 31, 2014, credit collateral held from counterparties where Generation had credit exposure included $69 million of cash and $16 million of letters of credit.

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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. See Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. 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, 2014. See Note 3—Regulatory Matters 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, 2014, 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—Significant Accounting Policies 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, 2014.

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, 2014, PECO had no net credit exposure with suppliers.

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PECO does not obtain cash collateral from suppliers under its natural gas supply and asset management agreements. As of December 31, 2014, PECO had credit exposure of $8 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—Significant Accounting Policies 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 Public Utilities Article of the Annotated Code of Maryland 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, 2014.

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, 2014, 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, 2014, 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.

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

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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 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements.

Generation transacts 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 or fall below contracted price levels, Generation or its counterparties may be required to post collateral with one another. In order to post collateral, Generation depends on access to bank credit facilities which serve as liquidity sources to fund collateral requirements. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

As of December 31, 2014, Generation had cash collateral of $1,497 million posted and cash collateral held of $77 million for counterparties with derivative positions, of which $1,406 million and $6 million in net cash collateral deposits were offset against energy mark-to-market and interest rate and foreign exchange derivative assets and liabilities related to underlying energy contracts, respectively. As of December 31, 2014, $8 million of cash collateral posted was not offset against net derivative positions because it was not associated with energy-related derivatives or as of the balance sheet date there were no positions to offset. As of December 31, 2013, Generation had cash collateral posted of $72 million and cash collateral held of $206 million for counterparties with derivative positions, of which $144 million in net cash collateral deposits were offset against mark-to-market assets and liabilities. As of December 31, 2013, $10 million of cash collateral posted was not offset against net mark-to-market assets and liabilities because it was not associated with energy-related derivatives or at the balance sheet date there were no positions to offset. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

ComEd

As of December 31, 2014, ComEd held approximately $2 million of collateral from suppliers in association with energy procurement contracts and held approximately $19 million in the form of cash for both annual and long-term renewable energy contracts. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

PECO

As of December 31, 2014, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

BGE

BGE is not required to post collateral under its electric supply contracts. As of December 31, 2014, 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 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

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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, CAISO, 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. In 2014 the exchanges increased initial margin rates, which required Generation to post higher amounts of initial margin collateral. Generation believes that increased market volatility and extreme weather events, such as the Polar Vortex, contributed to the rate increases.

Long-Term Leases (Exelon)

Exelon’s Consolidated Balance Sheet, as of December 31, 2014, included a $361 million net investment in coal-fired plants in Georgia subject to long-term leases. This investment represents the estimated residual value of leased assets at the end of the respective lease terms of $685 million, less unearned income of $324 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessee does not exercise the fixed purchase options, Exelon has the ability to operate the stations and keep or market the power itself or require the lessee to arrange for a third-party to bid on a service contract for a period following the lease term. Exelon will be subject to residual value risk if the lessee does not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract 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. Management regularly evaluates the creditworthiness of Exelon’s counterparties to these long-term leases. Exelon monitors the continuing credit quality of the credit enhancement party.

Exelon’s Consolidated Balance Sheet, as of December 31, 2013, also included a net investment in a coal-fired plant in Texas subject to a long-term lease. In February 2014, Exelon and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate the leases prior to their expiration dates. As a result of the lease termination, Exelon received a net early termination amount of $335 million from CPS and wrote off the net investment in the CPS long-term lease of $336 million; resulting in a pre-tax loss of $1 million. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for the impact of the lease termination on income taxes.

Pursuant to the applicable accounting guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and, if the review indicates a

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fair value below the carrying value and the decline is determined to be other than temporary, must record an impairment charge in the period the estimate changed. Based on the annual reviews performed in 2014 and 2013, the estimated residual value of Exelon’s direct financing leases for the Georgia generating stations experienced other than temporary declines given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $24 million and $14 million pre-tax impairment charge in 2014 and 2013, respectively, for these stations. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for further information.

Interest Rate and Foreign Exchange 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, 2014, Exelon and Generation had $1,450 million and $550 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $3,070 million and $770 million of notional amounts of floating-to-fixed hedges outstanding, respectively. 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 fixed-to-floating swaps would result in approximately a $8 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2014. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges.

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, 2014, 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 $617 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’s integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services, and engages in natural gas and oil exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. These segments are discussed in further detail in “ITEM 1. BUSINESS—Exelon Generation Company, LLC” 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 Corporation—Executive Overview” of this Form 10-K.

Results of Operations

Year Ended December 31, 2014 Compared To Year Ended December 31, 2013 and Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

A discussion of Generation’s results of operations for 2014 compared to 2013 and 2013 compared to 2012 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 $5.8 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.

See the “EXELON CORPORATION—Liquidity and Capital Resources” and Note 13 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.

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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.

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, 2014 Compared to Year Ended December 31, 2013 and Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

A discussion of ComEd’s results of operations for 2014 compared to 2013 and for 2013 compared to 2012 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, 2014, 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 13 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.

194

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.”

195

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, 2014 Compared to Year Ended December 31, 2013 and Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

A discussion of PECO’s results of operations for 2014 compared to 2013 and for 2013 compared to 2012 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, 2014, 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.

196

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.”

197

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, 2014 Compared to Year Ended December 31, 2013 and Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

A discussion of BGE’s results of operations for 2014 compared to 2013 and for 2013 compared to 2012 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, 2014, 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.

198

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—Significant Accounting Policies 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.”

199

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, 2014. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2014, Exelon’s internal control over financial reporting was effective.

We excluded Integrys, which we acquired on November 1, 2014, from management’s assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2014. This exclusion is in accordance with the SEC’s general guidance that an assessment of a recently acquired business may be omitted from our scope in the year of acquisition.

The effectiveness of the Exelon’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 13, 2015

200

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, 2014. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, as of December 31, 2014, Generation’s internal control over financial reporting was effective.

We excluded Integrys, which we acquired on November 1, 2014, from management’s assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2014. This exclusion is in accordance with the SEC’s general guidance that an assessment of a recently acquired business may be omitted from our scope in the year of acquisition.

The effectiveness of the Generation’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 13, 2015

201

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, 2014. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ComEd’s management concluded that, as of December 31, 2014, ComEd’s internal control over financial reporting was effective.

The effectiveness of the ComEd’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 13, 2015

202

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, 2014. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PECO’s management concluded that, as of December 31, 2014, PECO’s internal control over financial reporting was effective.

The effectiveness of the PECO’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 13, 2015

203

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, 2014. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, BGE’s management concluded that, as of December 31, 2014, BGE’s internal control over financial reporting was effective.

The effectiveness of BGE’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 13, 2015

204

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 (the “Company”) and its subsidiaries at December 31, 2014 and 2013 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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) 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, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. 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.

As described in Management’s Report on Internal Control over Financial Reporting appearing under Item 8, management has excluded Integrys Energy Services, Inc. (“Integrys”) from its

205

assessment of internal control over financial reporting as of December 31, 2014 because it was acquired by the Company in a purchase business combination on November 1, 2014. We have also excluded Integrys from our audit of internal control over financial reporting. Integrys is a wholly-owned subsidiary whose total assets and total revenues represent 0.74% and 1.41%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 13, 2015

206

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 (the “Company”) and its subsidiaries at December 31, 2014 and 2013 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. 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.

207

As described in Management’s Report on Internal Control over Financial Reporting appearing under Item 8, management has excluded Integrys Energy Services, Inc. (“Integrys”) from its assessment of internal control over financial reporting as of December 31, 2014 because it was acquired by the Company in a purchase business combination on November 1, 2014. We have also excluded Integrys from our audit of internal control over financial reporting. Integrys is a wholly-owned subsidiary whose total assets and total revenues represent 1.42% and 2.22%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 13, 2015

208

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 (the “Company”) and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. 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 13, 2015

209

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 (the “Company”) and its subsidiaries at December 31, 2014 and 2013 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. 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 13, 2015

210

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 (the “Company”) and its subsidiaries at December 31, 2014 and 2013 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. 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

Baltimore, Maryland

February 13, 2015

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212

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions, except per share data)	2014			2013			2012
Operating revenues	$	27,429		$	24,888		$	23,489
Operating expenses
Purchased power and fuel		12,472			9,468			9,121
Purchased power and fuel from affiliates		531			1,256			1,036
Operating and maintenance		8,568			7,270			7,961
Depreciation and amortization		2,314			2,153			1,881
Taxes other than income		1,154			1,095			1,019

Total operating expenses		25,039			21,242			21,018

Equity in (losses) earnings of unconsolidated affiliates		(20	)		10			(91	)
Gain (loss) on sales of assets		437			13			(7	)
Gain on consolidation and acquisition of businesses		289			—			—

Operating income		3,096			3,669			2,373

Other income and (deductions)
Interest expense, net		(1,024	)		(1,315	)		(891	)
Interest expense to affiliates, net		(41	)		(41	)		(37	)
Other, net		455			460			353

Total other income and (deductions)		(610	)		(896	)		(575	)

Income before income taxes		2,486			2,773			1,798
Income taxes		666			1,044			627

Net income		1,820			1,729			1,171
Net income attributable to noncontrolling interest, preferred security dividends and preference stock dividends		197			10			11

Net income attributable to common shareholders		1,623			1,719			1,160

Comprehensive income (loss), net of income taxes
Net income		1,820			1,729			1,171
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service (benefit) cost reclassified to periodic benefit cost		(30	)		—			1
Actuarial loss reclassified to periodic cost		147			208			168
Transition obligation reclassified to periodic cost		—			—			2
Pension and non-pension postretirement benefit plan valuation adjustment		(497	)		669			(371	)
Unrealized loss on cash flow hedges		(148	)		(248	)		(120	)
Unrealized gain on marketable securities		1			2			2
Unrealized gain on equity investments		8			106			1
Unrealized loss on foreign currency translation		(9	)		(10	)		—
Reversal of CENG equity method AOCI		(116	)		—			—

Other comprehensive (loss) income		(644	)		727			(317	)

Comprehensive income	$	1,176		$	2,456		$	854

Average shares of common stock outstanding:
Basic		860			856			816
Diluted		864			860			819
Earnings per average common share:
Basic	$	1.89		$	2.01		$	1.42
Diluted	$	1.88		$	2.00		$	1.42

Dividends per common share	$	1.24		$	1.46		$	2.10

See the Combined Notes to Consolidated Financial Statements

213

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2014			2013			2012
Cash flows from operating activities
Net income	$	1,820		$	1,729		$	1,171
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		3,868			3,779			4,079
Impairment of long-lived assets		687			171			284
Gain on consolidation and acquisition of businesses		(296	)		—			—
(Gain) loss on sales of assets		(437	)		(13	)		7
Deferred income taxes and amortization of investment tax credits		502			119			615
Net fair value changes related to derivatives		716			(445	)		(604	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(210	)		(170	)		(157	)
Other non-cash operating activities		1,054			718			1,364
Changes in assets and liabilities:
Accounts receivable		(318	)		(97	)		243
Inventories		(380	)		(100	)		26
Accounts payable, accrued expenses and other current liabilities		209			(90	)		(632	)
Option premiums received (paid), net		38			(36	)		(114	)
Counterparty collateral (posted) received, net		(1,478	)		215			135
Income taxes		(143	)		883			544
Pension and non-pension postretirement benefit contributions		(617	)		(422	)		(462	)
Other assets and liabilities		(558	)		102			(368	)

Net cash flows provided by operating activities		4,457			6,343			6,131

Cash flows from investing activities
Capital expenditures		(6,077	)		(5,395	)		(5,789	)
Proceeds from termination of direct financing lease investment		335			—			—
Proceeds from nuclear decommissioning trust fund sales		7,396			4,217			7,265
Investment in nuclear decommissioning trust funds		(7,551	)		(4,450	)		(7,483	)
Cash and restricted cash acquired from consolidations and acquisitions		140			—			964
Acquisitions of businesses		(386	)		—			(21	)
Proceeds from sales of long-lived assets		1,719			32			371
Proceeds from sales of investments		7			22			28
Purchases of investments		(3	)		(4	)		(13	)
Change in restricted cash		(104	)		(43	)		(34	)
Distribution from CENG		13			115			—
Other investing activities		(88	)		112			136

Net cash flows used in investing activities		(4,599	)		(5,394	)		(4,576	)

Cash flows from financing activities
Payment of accounts receivable agreement		—			(210	)		(15	)
Changes in short-term borrowings		122			332			(197	)
Issuance of long-term debt		3,463			2,055			2,027
Retirement of long-term debt		(1,545	)		(1,589	)		(1,145	)
Redemption of preferred securities		—			(93	)		—
Distributions to noncontrolling interest of consolidated VIE		(421	)		—			—
Dividends paid on common stock		(1,065	)		(1,249	)		(1,716	)
Proceeds from employee stock plans		35			47			72
Other financing activities		(178	)		(119	)		(111	)

Net cash flows provided by (used in) financing activities		411			(826	)		(1,085	)

Increase in cash and cash equivalents		269			123			470
Cash and cash equivalents at beginning of period		1,609			1,486			1,016

Cash and cash equivalents at end of period	$	1,878		$	1,609		$	1,486

See the Combined Notes to Consolidated Financial Statements

214

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	1,878	$	1,609
Restricted cash and cash equivalents		271		167
Accounts receivable, net
Customer		3,482		2,981
Other		1,227		1,175
Mark-to-market derivative assets		1,279		727
Unamortized energy contract assets		254		374
Inventories, net
Fossil fuel		579		276
Materials and supplies		1,024		829
Deferred income taxes		244		573
Regulatory assets		847		760
Assets held for sale		147		14
Other		865		652

Total current assets		12,097		10,137

Property, plant and equipment, net		52,087		47,330
Deferred debits and other assets
Regulatory assets		6,076		5,910
Nuclear decommissioning trust funds		10,537		8,071
Investments		544		1,187
Investment in CENG		—		1,925
Goodwill		2,672		2,625
Mark-to-market derivative assets		773		607
Unamortized energy contract assets		549		710
Pledged assets for Zion Station decommissioning		319		458
Other		1,160		964

Total deferred debits and other assets		22,630		22,457

Total assets ^(a)	$	86,814	$	79,924

See the Combined Notes to Consolidated Financial Statements

215

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014			2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	460		$	341
Long-term debt due within one year		1,802			1,509
Accounts payable		3,048			2,484
Accrued expenses		1,539			1,633
Payables to affiliates		8			116
Deferred income taxes		—			40
Regulatory liabilities		310			327
Mark-to-market derivative liabilities		234			159
Unamortized energy contract liabilities		238			261
Other		1,123			858

Total current liabilities		8,762			7,728

Long-term debt		19,362			17,623
Long-term debt to financing trusts		648			648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		13,019			12,905
Asset retirement obligations		7,295			5,194
Pension obligations		3,366			1,876
Non-pension postretirement benefit obligations		1,742			2,190
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,550			4,388
Mark-to-market derivative liabilities		403			300
Unamortized energy contract liabilities		211			266
Payable for Zion Station decommissioning		155			305
Other		2,147			2,540

Total deferred credits and other liabilities		33,909			30,985

Total liabilities ^(a)		62,681			56,984

Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 860 and 857 shares outstanding at December 31, 2014 and 2013, respectively)		16,709			16,741
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013)		(2,327	)		(2,327	)
Retained earnings		10,910			10,358
Accumulated other comprehensive loss, net		(2,684	)		(2,040	)

Total shareholders’ equity		22,608			22,732
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		1,332			15

Total equity		24,133			22,940

Total liabilities and shareholders’ equity	$	86,814		$	79,924

(a)

Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2—Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

216

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			Non-controlling Interest			Preferred and Preference Stock			Total Shareholders’ Equity
Balance, December 31, 2011		698,112	$	9,107		$	(2,327	)	$	10,055		$	(2,450	)	$	3		$	—		$	14,388
Net income (loss)		—		—			—			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		—		—			—			—			(317	)		—			—			(317	)

Balance, December 31, 2012		889,525	$	16,632		$	(2,327	)	$	9,893		$	(2,767	)	$	106		$	193		$	21,730
Net income (loss)		—		—			—			1,719			—			(10	)		20			1,729
Long-term incentive plan activity		1,445		81			—			—			—			—			—			81
Employee stock purchase plan issuances		1,064		28			—			—			—			—			—			28
Common stock dividends		—		—			—			(1,254	)		—			—			—			(1,254	)
Consolidated VIE dividend to noncontrolling interest		—		—			—			—			—			(63	)		—			(63	)
Deconsolidation of VIE		—		—			—			—			—			(18	)		—			(18	)
Redemption of preferred securities		—		—			—			—			—			—			(6	)		(6	)
Preferred and preference stock dividends		—		—			—			—			—			—			(14	)		(14	)
Other comprehensive income, net of income taxes		—		—			—			—			727			—			—			727

Balance, December 31, 2013		892,034	$	16,741		$	(2,327	)	$	10,358		$	(2,040	)	$	15		$	193		$	22,940
Net income (loss)		—		—			—			1,623			—			184			13			1,820
Long-term incentive plan activity		1,574		72			—			—			—			—			—			72
Employee stock purchase plan issuances		960		35			—			—			—			—			—			35
Tax benefit on stock compensation		—		(8	)		—			—			—			—			—			(8	)
Acquisition of noncontrolling interest		—		(2	)		—			—			—			6			—			4
Common stock dividends		—		—			—			(1,071	)		—			—			—			(1,071	)
Preferred and preference stock dividends		—		—			—			—			—			—			(13	)		(13	)
Fair value of financing contract payments		—		(131	)		—			—			—			—			—			(131	)
Noncontrolling interest established upon consolidation of CENG		—		—			—			—			—			1,548			—			1,548
Transfer of CENG pension and non-pension postretirement benefit obligations		—		2			—			—			—			—			—			2
Consolidated VIE dividend to noncontrolling interest		—		—			—			—			—			(421	)		—			(421	)
Reversal of CENG equity method AOCI, net of income taxes		—		—			—			—			(116	)		—			—			(116	)
Other comprehensive loss, net of income taxes		—		—			—			—			(528	)		—			—			(528	)

Balance, December 31, 2014		894,568	$	16,709		$	(2,327	)	$	10,910		$	(2,684	)	$	1,332		$	193		$	24,133

See the Combined Notes to Consolidated Financial Statements

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218

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2014			2013			2012
Operating revenues
Operating revenues	$	16,614		$	14,207		$	12,735
Operating revenues from affiliates		779			1,423			1,702

Total operating revenues		17,393			15,630			14,437

Operating expenses
Purchased power and fuel		9,368			6,927			6,017
Purchased power and fuel from affiliates		557			1,270			1,044
Operating and maintenance		4,943			3,960			4,398
Operating and maintenance from affiliates		623			574			630
Depreciation and amortization		967			856			768
Taxes other than income		465			389			369

Total operating expenses		16,923			13,976			13,226

Equity in (losses) earnings of unconsolidated affiliates		(20	)		10			(91	)
Gain (loss) on sales of assets		437			13			(7	)
Gain on consolidation and acquisition of businesses		289			—			—

Operating income		1,176			1,677			1,113

Other income and (deductions)
Interest expense		(303	)		(298	)		(226	)
Interest expense to affiliates, net		(53	)		(59	)		(75	)
Other, net		406			355			246

Total other income and (deductions)		50			(2	)		(55	)

Income before income taxes		1,226			1,675			1,058
Income taxes		207			615			500

Net income		1,019			1,060			558
Net income (loss) attributable to noncontrolling interests		184			(10	)		(4	)

Net income attributable to membership interest		835			1,070			562

Comprehensive income (loss), net of income taxes
Net income		1,019			1,060			558
Other comprehensive income (loss), net of income taxes
Unrealized loss on cash flow hedges		(132	)		(398	)		(403	)
Unrealized gain on equity investments		8			107			1
Unrealized loss on foreign currency translation		(9	)		(10	)		—
Unrealized gain (loss) on marketable securities		(1	)		2			—
Reversal of CENG equity method AOCI		(116	)		—			—

Other comprehensive loss		(250	)		(299	)		(402	)

Comprehensive Income	$	769		$	761		$	156

See the Combined Notes to Consolidated Financial Statements

219

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2014			2013			2012
Cash flows from operating activities
Net income	$	1,019		$	1,060		$	558
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		2,519			2,559			2,966
Impairment of long-lived assets		663			157			284
Gain on consolidation and acquisition of businesses		(296	)		—			—
(Gain) loss on sales of assets		(437	)		(13	)		7
Deferred income taxes and amortization of investment tax credits		(198	)		315			408
Net fair value changes related to derivatives		635			(448	)		(611	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(210	)		(170	)		(157	)
Other non-cash operating activities		346			270			518
Changes in assets and liabilities:
Accounts receivable		(215	)		109			248
Receivables from and payables to affiliates, net		15			2			39
Inventories		(359	)		(88	)		31
Accounts payable, accrued expenses and other current liabilities		94			(109	)		(499	)
Option premiums received (paid), net		38			(36	)		(114	)
Counterparty collateral (posted) received, net		(1,507	)		162			95
Income taxes		265			402			114
Pension and non-pension postretirement benefit contributions		(297	)		(149	)		(178	)
Other assets and liabilities		(249	)		(136	)		(128	)

Net cash flows provided by operating activities		1,826			3,887			3,581

Cash flows from investing activities
Capital expenditures		(3,012	)		(2,752	)		(3,554	)
Proceeds from nuclear decommissioning trust fund sales		7,396			4,217			7,265
Investment in nuclear decommissioning trust funds		(7,551	)		(4,450	)		(7,483	)
Cash and restricted cash acquired from consolidations and acquisitions		140			—			708
Proceeds from sales of long-lived assets		1,719			32			371
Acquisitions of businesses		(386	)		—			(21	)
Change in restricted cash		(87	)		(64	)		4
Changes in Exelon intercompany money pool		44			(44	)		—
Distribution from CENG		13			115			—
Other investing activities		(43	)		30			81

Net cash flows used in investing activities		(1,767	)		(2,916	)		(2,629	)

Cash flows from financing activities
Change in short-term borrowings		17			13			(52	)
Issuance of long-term debt		1,112			854			1,076
Retirement of long-term debt		(586	)		(570	)		(145	)
Distribution to member		(645	)		(625	)		(1,626	)
Contribution from member		53			26			48
Distribution to noncontrolling interest of consolidated VIE		(421	)		—			—
Other financing activities		(67	)		(82	)		(78	)

Net cash flows used in financing activities		(537	)		(384	)		(777	)

Increase (decrease) in cash and cash equivalents		(478	)		587			175
Cash and cash equivalents at beginning of period		1,258			671			496

Cash and cash equivalents at end of period	$	780		$	1,258		$	671

See the Combined Notes to Consolidated Financial Statements

220

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets


(In millions)	December 31,
(In millions)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	780	$	1,258
Restricted cash and cash equivalents		158		71
Accounts receivable, net
Customer		2,295		1,689
Other		318		353
Mark-to-market derivative assets		1,276		727
Receivables from affiliates		113		108
Receivable from Exelon intercompany money pool		—		44
Unamortized energy contract assets		254		374
Inventories, net
Fossil fuel		465		164
Materials and supplies		847		671
Deferred income taxes		327		475
Assets held for sale		147		14
Other		658		491

Total current assets		7,638		6,439

Property, plant and equipment, net		22,945		20,111
Deferred debits and other assets
Nuclear decommissioning trust funds		10,537		8,071
Investments		104		400
Investment in CENG		—		1,925
Goodwill		47		—
Mark-to-market derivative assets		771		600
Prepaid pension asset		1,704		1,873
Pledged assets for Zion Station decommissioning		319		458
Unamortized energy contract assets		549		710
Deferred income taxes		3		—
Other		731		645

Total deferred debits and other assets		14,765		14,682

Total assets ^(a)	$	45,348	$	41,232

See the Combined Notes to Consolidated Financial Statements

221

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014			2013
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	36		$	22
Long-term debt due within one year		58			561
Long-term debt to affiliates due within one year		556			—
Accounts payable		1,759			1,322
Accrued expenses		886			976
Payables to affiliates		107			181
Deferred income taxes		—			25
Mark-to-market derivative liabilities		214			142
Unamortized energy contract liabilities		238			249
Other		605			389

Total current liabilities		4,459			3,867

Long-term debt		6,709			5,645
Long-term debt to affiliate		943			1,523
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		6,034			6,295
Asset retirement obligations		7,146			5,047
Non-pension postretirement benefit obligations		915			850
Spent nuclear fuel obligation		1,021			1,021
Payables to affiliates		2,880			2,740
Mark-to-market derivative liabilities		105			120
Unamortized energy contract liabilities		211			266
Payable for Zion Station decommissioning		155			305
Other		719			811

Total deferred credits and other liabilities		19,186			17,455

Total liabilities ^(a)		31,297			28,490

Commitments and contingencies
Equity
Member’s equity
Membership interest		8,951			8,898
Undistributed earnings		3,803			3,613
Accumulated other comprehensive income (loss), net		(36	)		214

Total member’s equity		12,718			12,725
Noncontrolling interest		1,333			17

Total equity		14,051			12,742

Total liabilities and equity	$	45,348		$	41,232

(a)

Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2—Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

222

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 (loss)			Noncontrolling Interest			Total Equity
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
Constellation Merger		5,264			—			—			—			5,264
Noncontrolling interest acquired		8			—			—			107			115
Other comprehensive loss, net of income taxes		—			—			(402	)		—			(402	)

Balance, December 31, 2012	$	8,876		$	3,168		$	513		$	108		$	12,665
Net income		—			1,070			—			(10	)		1,060
Distribution to member		—			(625	)		—			—			(625	)
Allocation of tax benefit from member		26			—			—			—			26
Consolidated VIE dividend to noncontrolling interest		—			—			—			(63	)		(63	)
Deconsolidation of VIE		(1	)		—			—			(18	)		(19	)
Noncontrolling interest acquired		(3	)		—			—			—			(3	)
Other comprehensive loss, net of income taxes		—			—			(299	)		—			(299	)

Balance, December 31, 2013	$	8,898		$	3,613		$	214		$	17		$	12,742
Net income		—			835			—			184			1,019
Acquisition of noncontrolling interest		—			—			—			5			5
Allocation of tax benefit from member		53			—			—			—			53
Distribution to member		—			(645	)		—			—			(645	)
Noncontrolling interest established upon consolidation of CENG		—			—			—			1,548			1,548
Consolidated VIE dividend to noncontrolling interest		—			—			—			(421	)		(421	)
Reversal of CENG equity method AOCI, net of income taxes of $(77)		—			—			(116	)		—			(116	)
Other comprehensive loss, net of income taxes		—			—			(134	)		—			(134	)

Balance, December 31, 2014	$	8,951		$	3,803		$	(36	)	$	1,333		$	14,051

See the Combined Notes to Consolidated Financial Statements

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224

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(in millions)	2014			2013			2012
Operating revenues
Operating revenues	$	4,560		$	4,461		$	5,441
Operating revenues from affiliates		4			3			2

Total operating revenues		4,564			4,464			5,443

Operating expenses
Purchased power		1,001			662			1,518
Purchased power from affiliate		176			512			789
Operating and maintenance		1,263			1,211			1,182
Operating and maintenance from affiliate		166			157			163
Depreciation and amortization		687			669			610
Taxes other than income		293			299			295

Total operating expenses		3,586			3,510			4,557

Gain on sales of assets		2			—			—

Operating income		980			954			886

Other income and (deductions)
Interest expense		(308	)		(566	)		(294	)
Interest expense to affiliates, net		(13	)		(13	)		(13	)
Other, net		17			26			39

Total other income and (deductions)		(304	)		(553	)		(268	)

Income before income taxes		676			401			618
Income taxes		268			152			239

Net income		408			249			379

Other comprehensive income
Unrealized gain on marketable securities, net of income taxes of $0, $0 and $0, respectively		—			—			1

Other comprehensive income		—			—			1

Comprehensive income	$	408		$	249		$	380

See the Combined Notes to Consolidated Financial Statements

225

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended
(In millions)	2014			2013			2012
Cash flows from operating activities
Net income	$	408		$	249		$	379
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		687			669			610
Deferred income taxes and amortization of investment tax credits		433			(57	)		270
Other non-cash operating activities		255			28			252
Changes in assets and liabilities:
Accounts receivable		(121	)		(12	)		24
Receivables from and payables to affiliates, net		(11	)		(12	)		(18	)
Inventories		(16	)		(18	)		(11	)
Accounts payable, accrued expenses and other current liabilities		53			74			59
Income taxes		(159	)		178			9
Pension and non-pension postretirement benefit contributions		(248	)		(122	)		(138	)
Other assets and liabilities		45			241			(102	)

Net cash flows provided by operating activities		1,326			1,218			1,334

Cash flows from investing activities
Capital expenditures		(1,689	)		(1,433	)		(1,246	)
Proceeds from sales of investments		7			7			28
Purchases of investments		(3	)		(4	)		(13	)
Change in restricted cash		(2	)		(2	)		—
Other investing activities		32			45			19

Net cash flows used in investing activities		(1,655	)		(1,387	)		(1,212	)

Cash flows from financing activities
Changes in short-term borrowings		120			184			—
Issuance of long-term debt		900			350			350
Retirement of long-term debt		(617	)		(252	)		(450	)
Contributions from parent		273			—			—
Dividends paid on common stock		(307	)		(220	)		(105	)
Other financing activities		(10	)		(1	)		(7	)

Net cash flows provided by (used in) financing activities		359			61			(212	)

Increase (decrease) in cash and cash equivalents		30			(108	)		(90	)
Cash and cash equivalents at beginning of period		36			144			234

Cash and cash equivalents at end of period	$	66		$	36		$	144

See the Combined Notes to Consolidated Financial Statements

226

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheet


	December 31,
(In millions)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	66	$	36
Restricted cash		4		2
Accounts receivable, net
Customer		477		451
Other		648		581
Receivables from affiliates		14		3
Inventories, net		125		109
Regulatory assets		349		329
Other		40		29

Total current assets		1,723		1,540

Property, plant and equipment, net		15,793		14,666
Deferred debits and other assets
Regulatory assets		852		933
Investments		6		11
Goodwill		2,625		2,625
Receivable from affiliates		2,571		2,469
Prepaid pension asset		1,551		1,583
Other		271		291

Total deferred debits and other assets		7,876		7,912

Total assets	$	25,392	$	24,118

See the Combined Notes to Consolidated Financial Statements

227

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014		2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	304	$	184
Long-term debt due within one year		260		617
Accounts payable		598		449
Accrued expenses		331		307
Payables to affiliates		84		83
Customer deposits		128		133
Regulatory liabilities		125		170
Mark-to-market derivative liability		20		17
Deferred income taxes		63		16
Other		73		72

Total current liabilities		1,986		2,048

Long-term debt		5,698		5,058
Long-term debt to financing trust		206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		4,498		4,116
Asset retirement obligations		103		99
Non-pension postretirement benefits obligations		263		381
Regulatory liabilities		3,655		3,512
Mark-to-market derivative liability		187		176
Other		889		994

Total deferred credits and other liabilities		9,595		9,278

Total liabilities		17,485		16,590

Commitments and contingencies
Shareholders’ equity
Common stock		1,588		1,588
Other paid-in capital		5,468		5,190
Retained earnings		851		750

Total shareholders’ equity		7,907		7,528

Total liabilities and shareholders’ equity	$	25,392	$	24,118

See the Combined Notes to Consolidated Financial Statements

228

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, 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
Net income		—		—		249			—			—			249
Common stock dividends		—		—		—			(220	)		—			(220	)
Parent tax matter indemnification		—		176		—			—			—			176
Appropriation of retained earnings for future dividends		—		—		(249	)		249			—			—

Balance, December 31, 2013	$	1,588	$	5,190	$	(1,639	)	$	2,389		$	—		$	7,528
Net income		—		—		408			—			—			408
Common stock dividends		—		—		—			(307	)		—			(307	)
Contribution from parent		—		273		—			—			—			273
Parent tax matter indemnification		—		5		—			—			—			5
Appropriation of retained earnings for future dividends		—		—		(408	)		408			—			—

Balance, December 31, 2014	$	1,588	$	5,468	$	(1,639	)	$	2,490		$	—		$	7,907

See the Combined Notes to Consolidated Financial Statements

229

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230

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2014			2013			2012
Operating revenues
Operating revenues	$	3,092		$	3,099		$	3,183
Operating revenues from affiliates		2			1			3

Total operating revenues		3,094			3,100			3,186

Operating expenses
Purchased power and fuel		1,067			908			842
Purchased power from affiliate		194			392			533
Operating and maintenance		767			647			698
Operating and maintenance from affiliates		99			101			111
Depreciation and amortization		236			228			217
Taxes other than income		159			158			162

Total operating expenses		2,522			2,434			2,563

Operating income		572			666			623

Other income and (deductions)
Interest expense		(101	)		(103	)		(111	)
Interest expense to affiliates, net		(12	)		(12	)		(12	)
Other, net		7			6			8

Total other income and (deductions)		(106	)		(109	)		(115	)

Income before income taxes		466			557			508
Income taxes		114			162			127

Net income		352			395			381
Preferred security dividends and redemption		—			7			4

Net income attributable to common shareholder		352			388			377

Comprehensive income, net of income taxes
Net income		352			395			381
Other comprehensive income
Unrealized gain on marketable securities, net of income taxes of $0, $0 and $0, respectively		—			—			1

Other comprehensive income		—			—			1

Comprehensive income	$	352		$	395		$	382

See the Combined Notes to Consolidated Financial Statements

231

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2014			2013			2012
Cash flows from operating activities
Net income	$	352		$	395		$	381
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		236			228			217
Deferred income taxes and amortization of investment tax credits		88			20			37
Other non-cash operating activities		92			108			125
Changes in assets and liabilities:
Accounts receivable		(16	)		(79	)		(14	)
Receivables from and payables to affiliates, net		(6	)		(18	)		13
Inventories		2			2			21
Accounts payable, accrued expenses and other current liabilities		54			41			(47	)
Income taxes		(57	)		87			174
Pension and non-pension postretirement benefit contributions		(16	)		(31	)		(45	)
Other assets and liabilities		(17	)		(6	)		16

Net cash flows provided by operating activities		712			747			878

Cash flows from investing activities
Capital expenditures		(661	)		(537	)		(422	)
Changes in intercompany money pool		—			—			82
Change in restricted cash		—			(2	)		2
Other investing activities		12			8			10

Net cash flows used in investing activities		(649	)		(531	)		(328	)

Cash flows from financing activities
Payment of accounts receivable agreement		—			(210	)		(15	)
Issuance of long-term debt		300			550			350
Retirement of long-term debt		(250	)		(300	)		(375	)
Contributions from parent		24			27			9
Dividends paid on common stock		(320	)		(332	)		(343	)
Dividends paid on preferred securities		—			(1	)		(4	)
Redemption of preferred securities		—			(93	)		—
Other financing activities		(4	)		(2	)		(4	)

Net cash flows used in financing activities		(250	)		(361	)		(382	)

Increase (decrease) in cash and cash equivalents		(187	)		(145	)		168
Cash and cash equivalents at beginning of period		217			362			194

Cash and cash equivalents at end of period	$	30		$	217		$	362

See the Combined Notes to Consolidated Financial Statements

232

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	30	$	217
Restricted cash and cash equivalents		2		2
Accounts receivable, net
Customer		320		360
Other		141		104
Receivables from affiliates		3		3
Inventories, net
Fossil fuel		57		60
Materials and supplies		22		21
Deferred income taxes		69		83
Prepaid utility taxes		10		3
Regulatory assets		29		17
Other		31		36

Total current assets		714		906

Property, plant and equipment, net		6,801		6,384
Deferred debits and other assets
Regulatory assets		1,529		1,448
Investments		31		31
Receivable from affiliates		490		447
Prepaid pension asset		344		363
Other		34		38

Total deferred debits and other assets		2,428		2,327

Total assets	$	9,943	$	9,617

See the Combined Notes to Consolidated Financial Statements

233

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014		2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	—	$	250
Accounts payable		337		285
Accrued expenses		91		106
Payables to affiliates		52		58
Customer deposits		52		49
Regulatory liabilities		90		106
Other		31		37

Total current liabilities		653		891

Long-term debt		2,246		1,947
Long-term debt to financing trusts		184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,671		2,487
Asset retirement obligations		29		29
Non-pension postretirement benefits obligations		287		286
Regulatory liabilities		657		629
Other		95		99

Total deferred credits and other liabilities		3,739		3,530

Total liabilities		6,822		6,552

Commitments and contingencies
Shareholders’ equity
Common stock		2,439		2,415
Retained earnings		681		649
Accumulated other comprehensive income, net		1		1

Total shareholders’ equity		3,121		3,065

Total liabilities and shareholders’ equity	$	9,943	$	9,617

See the Combined Notes to Consolidated Financial Statements

234

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Changes in Stockholders’ Equity


(In millions)	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income		Total Shareholders’ Equity
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
Net income		—		395			—		395
Common stock dividends		—		(332	)		—		(332	)
Preferred security dividends		—		(1	)		—		(1	)
Redemption of Preferred Dividends		—		(6	)		—		(6	)
Allocation of tax benefit from parent		27		—			—		27

Balance, December 31, 2013	$	2,415	$	649		$	1	$	3,065
Net income		—		352			—		352
Common stock dividends		—		(320	)		—		(320	)
Allocation of tax benefit from parent		24		—			—		24

Balance, December 31, 2014	$	2,439	$	681		$	1	$	3,121

See the Combined Notes to Consolidated Financial Statements

235

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236

Baltimore Gas and Electric Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2014			2013			2012
Operating revenues
Operating revenues	$	3,140		$	3,052		$	2,725
Operating revenues from affiliates		25			13			10

Total operating revenues		3,165			3,065			2,735

Operating expenses
Purchased power and fuel		1,035			969			973
Purchased power from affiliate		382			452			396
Operating and maintenance		614			551			622
Operating and maintenance from affiliates		103			83			106
Depreciation and amortization		371			348			298
Taxes other than income		221			213			208

Total operating expenses		2,726			2,616			2,603

Operating income		439			449			132

Other income and (deductions)
Interest expense		(90	)		(106	)		(128	)
Interest expense to affiliates, net		(16	)		(16	)		(16	)
Other, net		18			17			23

Total other income and (deductions)		(88	)		(105	)		(121	)

Income before income taxes		351			344			11
Income taxes		140			134			7

Net income		211			210			4
Preference stock dividends		13			13			13

Net income (loss) attributable to common shareholder	$	198		$	197		$	(9	)

Comprehensive income	$	211		$	210		$	4

See the Combined Notes to Consolidated Financial Statements

237

Baltimore Gas and Electric Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2014			2013			2012
Cash flows from operating activities
Net income	$	211		$	210		$	4
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		371			348			298
Deferred income taxes and amortization of investment tax credits		116			125			104
Other non-cash operating activities		180			153			193
Changes in assets and liabilities:
Accounts receivable		46			(127	)		(45	)
Receivables from and payables to affiliates, net		(1	)		(14	)		26
Inventories		(6	)		1			25
Accounts payable, accrued expenses and other current liabilities		(70	)		(14	)		(33	)
Counterparty collateral received, net		27			—			—
Income taxes		45			(33	)		14
Pension and non-pension postretirement benefit contributions		(16	)		(24	)		(16	)
Other assets and liabilities		(163	)		(64	)		(85	)

Net cash flows provided by operating activities		740			561			485

Cash flows from investing activities
Capital expenditures		(620	)		(587	)		(582	)
Change in restricted cash		(22	)		2			—
Other investing activities		20			14			9

Net cash flows used in investing activities		(622	)		(571	)		(573	)

Cash flows from financing activities
Changes in short-term borrowings		(15	)		135			—
Issuance of long-term debt		—			300			250
Retirement of long-term debt		(70	)		(467	)		(173	)
Dividends paid on preference stock		(13	)		(13	)		(13	)
Contributions from parent		—			—			66
Other financing activities		13			(3	)		(2	)

Net cash flows (used in) provided by financing activities		(85	)		(48	)		128

Increase (decrease) in cash and cash equivalents		33			(58	)		40
Cash and cash equivalents at beginning of period		31			89			49

Cash and cash equivalents at end of period	$	64		$	31		$	89

See the Combined Notes to Consolidated Financial Statements

238

Baltimore Gas and Electric Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	64	$	31
Restricted cash and cash equivalents		50		28
Accounts receivable, net
Customer		390		480
Other		82		114
Income taxes receivable		—		30
Inventories, net
Gas held in storage		57		53
Materials and supplies		30		28
Deferred income taxes		6		2
Prepaid utility taxes		59		57
Regulatory assets		214		181
Other		5		7

Total current assets		957		1,011

Property, plant and equipment, net		6,204		5,864
Deferred debits and other assets
Regulatory assets		510		524
Investments		12		13
Prepaid pension asset		370		423
Other		25		26

Total deferred debits and other assets		917		986

Total assets^(a)	$	8,078	$	7,861

See the Combined Notes to Consolidated Financial Statements

239

Baltimore Gas and Electric Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2014		2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	120	$	135
Long-term debt due within one year		75		70
Accounts payable		215		270
Accrued expenses		131		111
Deferred income taxes		52		27
Payables to affiliates		66		55
Customer deposits		92		76
Regulatory liabilities		44		48
Other		51		35

Total current liabilities		846		827

Long-term debt		1,867		1,941
Long-term debt to financing trust		258		258
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		1,865		1,773
Asset retirement obligations		17		19
Non-pension postretirement benefits obligations		212		217
Regulatory liabilities		200		204
Other		60		67

Total deferred credits and other liabilities		2,354		2,280

Total liabilities^(a)		5,325		5,306

Commitments and contingencies
Shareholders’ equity
Common stock		1,360		1,360
Retained earnings		1,203		1,005

Total shareholders’ equity		2,563		2,365

Preference stock not subject to mandatory redemption		190		190

Total equity		2,753		2,555

Total liabilities and shareholders’ equity	$	8,078	$	7,861

(a)

BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2—Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

240

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		Total Equity
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
Net income		—		210			210			—		210
Preference stock dividends		—		(13	)		(13	)		—		(13	)

Balance, December 31, 2013	$	1,360	$	1,005		$	2,365		$	190	$	2,555
Net income		—		211			211			—		211
Preference stock dividends		—		(13	)		(13	)		—		(13	)

Balance, December 31, 2014	$	1,360	$	1,203		$	2,563		$	190	$	2,753

See the Combined Notes to Consolidated Financial Statements

241

Combined Notes to Consolidated Financial Statements

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

Index to Combined Notes to Consolidated Financial Statements

The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the registrants to which the footnotes apply:

Applicable Notes

Registrant

Exelon Corporation

•

Exelon Generation Company, LLC

•

Commonwealth Edison Company

•

PECO Energy Company

•

Baltimore Gas And Electric Company

•

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 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 (“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—Mergers, Acquisitions, and Dispositions for further information regarding the merger transaction.

On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation consolidated CENG’s financial position and results of operations into their businesses. Prior to April 1, 2014, Exelon and Generation accounted for CENG as an equity method investment. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC for further information regarding the integration transaction.

The energy generation business includes:

•

Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and 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.

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.

242

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 and BGE continued to be subject to 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, 2014, 2013 and 2012 and the financial position as of December 31, 2014 and December 31, 2013. However, for Exelon’s consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2014.

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preference stock. Exelon owned none of PECO’s preferred securities, which PECO redeemed in 2013. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2014 and December 31, 2013, as equity, PECO’s preferred securities as preferred securities of subsidiary through their redemption in 2013, 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 certain Exelon Wind projects, of which Generation holds a majority interest of 99% for certain periods of time, and CENG, of which Generation holds a 50.01% interest. The remaining interests are included in noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2—Variable Interest Entities for further discussion of Exelon’s and Generation’s VIEs and the reversionary interests of the noncontrolling members for these certain subsidiaries.

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 additional12.5% 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, 2014 and December 31, 2013, as equity.

243

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, 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 certain financing trusts of ComEd, PECO, and BGE. 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.

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 the registrants’ Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants’ net income, financial positions, 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 regulation, 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

244

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 or revenue 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 Note 3—Regulatory Matters and Note 6—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 Constellation merger date, Exelon and Generation have currently elected to de-designate all of their commodity cash flow hedge positions. As ComEd receives full cost recovery for energy procurement and related costs from retail customers, ComEd records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. Refer to Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for further information.

245

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note 12—Derivative Financial Instruments for further information.

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 Other income and deductions (interest income) on their Consolidated Statements of Operations and Comprehensive Income.

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 14—Income Taxes for further information.

Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, Generation, ComEd, PECO and BGE)

Exelon, Generation, ComEd, PECO and BGE collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23—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.

246

Combined Notes to Consolidated Financial Statements—(Continued)

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

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

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2014 and 2013, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, as of December 31, 2014 and 2013, Generation’s restricted cash and cash equivalents primarily included cash at Antelope Valley required for debt service and construction and cash at Continental Wind and ExGen Texas Power, which is required for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2014 and 2013, ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As of December 31, 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. As of December 31, 2014 and 2013, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds and cash collateral held from suppliers.

Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2014 and 2013, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2014, Exelon, Generation, ComEd, PECO and BGE had 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 aging, 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 customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accounts on customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance for uncollectible accounts, which was consistent with ComEd and PECO, as described above. For additional information regarding the change in estimate, refer to Note 6—Accounts Receivable. 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. 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.

247

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, and

•

requires the entity that consolidates a VIE (the primary beneficiary) to disclose (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.

Based on the above accounting guidance, Exelon has adopted the following policies related to variable interest entities:

•

Exelon has disclosed, 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.

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, coal and oil. The costs of natural gas, propane, coal and oil are generally included in inventory when purchased and charged to fuel expense when used or sold.

Materials and Supplies. Materials and supplies inventory generally includes the 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.

248

Combined Notes to Consolidated Financial Statements—(Continued)

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

Marketable Securities (Exelon, Generation, ComEd, PECO and BGE)

All marketable securities are reported at fair value. Marketable securities held in the NDT funds, certain Generation Rabbi trust investments 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 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 Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on certain Generation Rabbi trust investments and BGE’s Rabbi trust investments are included in earnings at Exelon, Generation and BGE. Unrealized gains and losses, net of tax, for Generation’s, ComEd’s and PECO’s available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd’s and PECO’s available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 15—Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 23—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 construction-related direct labor and material costs. ComEd, PECO and BGE also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. 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.

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.

249

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 7—Property, Plant and Equipment, Note 9—Jointly Owned Electric and Note 23—Supplemental Financial Information for additional information regarding property, plant and equipment.

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. Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. On-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 22—Commitments and Contingencies for additional information regarding the SNF disposal fee.

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 and design 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. Capitalized development costs are charged to Operating and maintenance expense when project completion is no longer probable. At December 31, 2014 and 2013, there were not material capitalized development costs for projects not yet under construction included in Property, plant and equipment, net on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $13 million, $10 million and $4 million of costs were expensed by Exelon and Generation for the years ended December 31, 2014, 2013, and 2012, respectively. These costs primarily related to the possible development of new renewable energy projects.

250

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^(a)		Generation^(a)		ComEd		PECO		BGE
December 31, 2014	$	596	$	193	$	133	$	84	$	163
December 31, 2013		479		129		101		71		155

Amortization of capitalized software costs	Exelon^(a)(b)		Generation^(a)(b)		ComEd		PECO		BGE^(b)
2014	$	186	$	59	$	45	$	28	$	43
2013		198		67		52		33		36
2012		208		81		56		30		32

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.

(b)

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 year ended December 31, 2012.

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 7—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 oil and gas reserves are based on internal calculations.

Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would

251

Combined Notes to Consolidated Financial Statements—(Continued)

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

have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. With exception of income tax-related regulatory assets, generally, when the recovery period is more than one year, the amortization is recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s distribution formula rate regulatory asset and ComEd’s and BGE’s transmission formula rate regulatory assets is recorded to Operating revenues. Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

See Note 3—Regulatory Matters and Note 23—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 throughout 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 and Comprehensive Income or, in the case of the majority of ComEd’s, PECO’s, and BGE’s accretion, through an increase to regulatory assets. See Note 15—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.

252

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)(b)		Generation^(a)(b)		ComEd		PECO		BGE^(b)
2014	Total incurred interest^(c)	$	1,144	$	419	$	323	$	115	$	118
	Capitalized interest		63		63		—		—		—
	Credits to AFUDC debt and equity		37		—		5		8		24

2013	Total incurred interest^(c)	$	1,423	$	411	$	584	$	117	$	129
	Capitalized interest		54		54		—		—		—
	Credits to AFUDC debt and equity		35		—		16		6		13

2012	Total incurred interest^(c)	$	1,003	$	368	$	310	$	125	$	149
	Capitalized interest		67		67		—		—		—
	Credits to AFUDC debt and equity		25		—		9		6		15

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.

(b)

(c)	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 22—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. Indicators of impairment may include a deteriorating business climate, including, but not limited to, 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. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. 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 less costs to sell.

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. The cash flows from the generating units are generally evaluated at a regional portfolio level along with cash flows generated from the customer supply and risk management activities, including cash flows

253

Combined Notes to Consolidated Financial Statements—(Continued)

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

from contracts that are accounted for as intangible contract assets and liabilities recorded on the balance sheet. In certain cases, generation assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generation assets (typically contracted renewables). See Note 8—Impairment of Long-Lived Assets for additional information.

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 10—Intangible Assets for additional information regarding Exelon’s, Generation’s and ComEd’s goodwill.

Equity Method Investments. Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other than temporary in nature. 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.

Direct Financing Lease Investments. Direct financing lease investments represent the estimated residual values of leased coal-fired plants in Georgia. Exelon reviews the estimated residual values of its direct financing lease investments and records an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. See Note 8—Impairment of Long-Lived Assets for additional information.

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 are not designated or do not qualify 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, interest expense 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.

254

Combined Notes to Consolidated Financial Statements—(Continued)

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

For commodity derivative contracts 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 Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivatives executed to hedge economic risk related to commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company.

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. 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. 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. See Note 12—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 July 14, 2014, Exelon became the sponsor of all of CENG’s pension and other postretirement benefit 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 16—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, 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.

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.

255

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 management believes may significantly affect the Registrants.

Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist

In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants’ results of operations or cash flows.

Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force)

In November 2014, the FASB issued authoritative guidance that allows acquired entities to apply pushdown accounting (i.e., reflecting the acquirer’s basis of accounting for the acquired entity’s assets and liabilities) when an acquirer obtains control of them. At the same time, the SEC rescinded its guidance on pushdown accounting. The SEC’s guidance had required pushdown accounting in certain circumstances, made it optional in others and prevented it in still other circumstances. The new guidance is effective immediately for any future transaction or to the most recent event in which an acquirer obtains or obtained control of the acquired entity. The adoption of the guidance had no impact to the financial statements of the Registrants; however, the Registrants will assess the potential impact of the guidance on future acquisitions.

The following recently issued accounting standard is not yet required to be reflected in the combined financial statements of the Registrants.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new guidance replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2016. Early adoption is not permitted. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance.

256

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 affect the entity’s economic performance.

At December 31, 2014 and 2013, Exelon, Generation, and BGE collectively consolidated six and four VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary. As of December 31, 2014 and 2013, the Registrants had significant interests in six and eight other VIEs, respectively, 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, 2014 and 2013 are as follows:


	December 31, 2014						December 31, 2013
	Exelon^(a)(b)		Generation^(b)		BGE		Exelon ^(a)		Generation		BGE
Current assets	$	1,271	$	1,242	$	21	$	484	$	446	$	28
Noncurrent assets		7,580		7,566		3		1,905		1,884		3

Total assets	$	8,851	$	8,808	$	24	$	2,389	$	2,330	$	31

Current liabilities	$	611	$	526	$	77	$	566	$	481	$	74
Noncurrent liabilities		2,730		2,600		120		774		562		195

Total liabilities	$	3,341	$	3,126	$	197	$	1,340	$	1,043	$	269

(a)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

(b)	Includes total assets of $6.1 billion and total liabilities of $2.1 billion due to the consolidation of CENG. See Note 5— Investment in Constellation Energy Nuclear Group, LLC for additional information.

Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the table can only be settled using VIE resources.

Exelon, Generation and BGE’s consolidated VIEs consist of:

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 has determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE consolidates BondCo.

257

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 2014, 2013, and 2012, BGE remitted $85 million, $83 million, and $85 million, respectively, to BondCo.

BGE did not provide any additional financial support to BondCo during 2014. 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

•

Generation provides 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.

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) from First Solar, Inc., a 242-MW solar PV project under construction in northern Los Angeles County, California. 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 operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solar power facilities and provides limited recourse related to the Antelope Valley project. In addition, these solar VIE entities have an aggregate amount of outstanding debt with third parties of $642 million, as of December 31, 2014, for which the creditors have no

258

Combined Notes to Consolidated Financial Statements—(Continued)

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

recourse to Generation, however there is limited recourse to Generation with respect to remaining equity contributions necessary to complete the Antelope Valley project. For additional information on these project-specific financing arrangements refer to Note 13—Debt and Credit Agreements.

Retail Power Companies. In March 2014, Generation began consolidating retail power VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $5 million in credit support for the retail power companies. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs does not have a material impact on Generation’s financial results or financial condition.

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 with 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 the 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 equity 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 generation facilities. While Generation owns 100% of the majority of the wind project entities, nine of the projects have noncontrolling equity interests of 1% held by third parties. Generation’s current economic interests in eight of these projects is significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling 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 99% economic interests in the projects. However, no additional support to these projects beyond what was contractually required has been provided during 2014. As of December 31, 2014, 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 relates to the wind generating assets, PPA intangible assets and working capital amounts.

CENG. Through March 31, 2014, CENG was operated as a joint venture with EDF Inc. (EDFI) (a subsidiary of EDF) and was governed by a board of ten directors, five of which were appointed by Generation and five by EDF. CENG was designed to operate under joint and equal control of Generation and EDFI through the Board of Directors, subject to the Chairman of the Board’s final decision making authority on certain special matters; therefore, CENG was not subject to VIE guidance. Accordingly, Generation’s 50.01% interest in CENG was accounted for as an equity method investment. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI. As a result of executing the NOSA, CENG now qualifies as a VIE due to the disproportionate relationship between Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA. Further, since Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary of CENG and,

259

Combined Notes to Consolidated Financial Statements—(Continued)

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

therefore, is required to consolidate the financial position and results of operations of CENG. On April 1, 2014, Exelon and Generation derecognized Generation’s equity method investment in CENG and reflected all assets, liabilities, and the EDFI noncontrolling interest in CENG at fair value on the consolidated balance sheets of Exelon and Generation, resulting in the recognition of a $261 million gain in their respective Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. For additional information on this transaction refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC.

Generation and Exelon, where indicated, provide the following support to CENG (See Note 25—Related Party Transactions and Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information regarding Generation and Exelon’s transactions with CENG):

•

under the NOSA, Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI,

•

under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants,

•

under power purchase agreements with CENG, Generation purchased 85% of the available output generated by the CENG nuclear plants through the end of 2014 and will purchase 50.01% from 2015 through the end of the operating life of each respective plant,

•

Generation provided a $400 million loan to CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC for more details),

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 22—Commitments and Contingencies for more details),

•

in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid from 2013 through 2016. As of December 31, 2014, the remaining obligation is approximately $3 million,

•

Generation and EDFI share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance (See Note 22—Commitments and Contingencies for more details),

•

Generation provides a guarantee of approximately $7 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDFI executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,

•

Generation and EDFI are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 22—Commitments and Contingencies for more details), and

260

Combined Notes to Consolidated Financial Statements—(Continued)

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

•

Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

For each of the consolidated VIEs, except as otherwise noted:

•

The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;

•

Exelon, Generation and BGE did not provide any additional material financial support to the VIEs;

•

Exelon, Generation and BGE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and

•

the creditors of the VIEs did not have recourse to Exelon’s, Generation’s or BGE’s general credit.

As of December 31, 2014 and 2013, ComEd and PECO did not have any material consolidated VIEs.

261

Combined Notes to Consolidated Financial Statements—(Continued)

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

Assets and Liabilities of Consolidated VIEs

Included within the consolidated VIE table above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of December 31, 2014 and 2013, these assets and liabilities primarily consisted of the following:


	December 31, 2014						December 31, 2013
	Exelon		Generation		BGE		Exelon		Generation		BGE
Cash and cash equivalents	$	392	$	392	$	—	$	62	$	62	$	—
Restricted cash		117		96		21		80		52		28
Accounts receivable, net
Customer		297		297		—		260		260		—
Other		57		57		—		—		—		—
Mark-to-market derivatives assets		171		171		—		21		21		—
Inventory
Materials and supplies		172		172		—		—		—		—
Other current assets		33		26		—		34		23		—

Total current assets		1,239		1,211		21		457		418		28

Property, plant and equipment, net		4,638		4,638		—		1,171		1,171		—
Nuclear decommissioning trust funds		2,097		2,097		—		—		—		—
Goodwill		47		47		—		—		—		—
Mark-to-market derivatives assets		44		44		—		—		—		—
Other noncurrent assets		95		82		3		127		106		3

Total noncurrent assets		6,921		6,908		3		1,298		1,277		3

Total assets	$	8,160	$	8,119	$	24	$	1,755	$	1,695	$	31

Long-term debt due within one year	$	87	$	5	$	75	$	85	$	5	$	70
Accounts payable		292		292		—		170		170		—
Accrued expenses		111		108		2		26		22		4
Mark-to-market derivative liabilities		24		24		—		29		29		—
Unamortized energy contracts (liabilities)		22		22		—		5		5		—
Other current liabilities		25		25		—		5		5		—

Total current liabilities		561		476		77		320		236		74

Long-term debt		212		81		120		298		86		195
Asset retirement obligations		1,763		1,763		—		—		—		—
Pension obligation^(a)		9		9		—		—		—		—
Unamortized energy contracts (liabilities)		51		51		—		28		28		—
Other noncurrent liabilities		127		127		—		12		12		—

Noncurrent liabilities		2,162		2,031		120		338		126		195

Total liabilities	$	2,723	$	2,507	$	197	$	658	$	362	$	269

(a)	Includes the CNEG Retail Gas’ pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation’s balance sheet. See Note 16—Retirement Benefits for additional details.

Unconsolidated Variable Interest Entities

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount

262

Combined Notes to Consolidated Financial Statements—(Continued)

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

of the investments is reflected on Exelon’s and Generation’s Consolidated Balance Sheets in Investments and Other assets. 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 material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

As of December 31, 2014 and 2013, Exelon and Generation had significant unconsolidated variable interests in six and eight VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of Generation’s ownership interest in four unconsolidated VIEs in 2014, offset by the execution of an energy purchase and sale agreement with an unconsolidated VIE and an equity investment in another unconsolidated VIE. The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:


December 31, 2014	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	506	$	91	$	597
Total liabilities^(a)		237		49		286
Exelon’s ownership interest in VIE^(a)		—		9		9
Other ownership interests in VIE^(a)		269		33		302
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments		—		13		13
Contract intangible asset		9		—		9
Debt and payment guarantees		—		3		3
Net assets pledged for Zion Station decommissioning^(b)		27		—		27


December 31, 2013	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	128	$	332	$	460
Total liabilities^(a)		17		123		140
Exelon’s ownership interest in VIE^(a)		—		86		86
Other ownership interests in VIE^(a)		111		123		234
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments		7		67		74
Contract intangible asset		9		—		9
Debt and payment guarantees		—		5		5
Net assets pledged for Zion Station decommissioning^(b)		44		—		44

(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 Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $292 million and $414 million as of December 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

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

For each unconsolidated VIE, Exelon and Generation assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation 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 materially affect the fair value or risk of their variable interests in these variable interest entities.

Energy Purchase and Sale Agreements. Generation has several energy purchase and sale agreements with generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each entity, and determined that certain of the entities are VIEs because the entity absorbs risk through the sale of fixed price power and renewable energy credits. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.

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 sold power to the VIEs which, in turn, sold 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 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 was not required. During 2013, the third-party repaid their obligations of the loan with Generation which caused the entities to no longer be unconsolidated VIEs.

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 15—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. Other than the asset sale agreement, Exelon and Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions’ creditors do not have any recourse to Exelon’s or Generation’s general credit.

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 22—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

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

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 22—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.

Investment in Energy Development Projects and Energy Generating Facilities. Generation has several equity investments in energy development projects and energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because the entity has an insufficient amount of equity at risk to finance its activities, Generation guarantees the debt of the entity, provides equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.

ComEd, PECO and BGE

The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of BGE, BGE Capital Trust II are not consolidated in Exelon’s, ComEd’s, PECO’s or BGE’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13—Debt and Credit Agreements for additional information.

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

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 to modernize Illinois’ electric utility infrastructure. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in

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

January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. As of December 31, 2014, and December 31, 2013, ComEd had a regulatory asset associated with the distribution formula rate of $371 million and $463 million, respectively. The regulatory asset associated with distribution true-up is amortized to Operating revenues as the associated amounts are recovered through rates.

Annual Reconciliation

2014 Filing. On April 16, 2014, ComEd filed its annual distribution formula rate to request a total increase to the revenue requirement of $269 million. On December 11, 2014, the ICC issued its final order which increased the revenue requirement by $232 million, reflecting an increase of $160 million for the initial revenue requirement for 2014 and an increase of $72 million related to the annual reconciliation for 2013. Approximately $23 million of the total $37 million revenue requirement disallowance is recoverable through other rider-based mechanisms. The rate increase was set using an allowed return on capital of 7.06% (inclusive of an allowed return on common equity of 9.25% for 2014 less a performance metrics penalty of 5 basis points for the 2013 reconciliation). The rates took effect in January 2015. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC on January 28, 2015.

2013 Filing. On April 29, 2013, ComEd filed its annual distribution formula rate, which was updated in August 2013, to request a total increase to the revenue requirement of $353 million. On December 19, 2013, the ICC issued its final order which increased the revenue requirement by $341 million, reflecting an increase of $160 million for the initial revenue requirement for 2013 and an increase of $181 million for the annual reconciliation for 2012. The final revenue requirement reflected the impacts of Senate Bill 9, which became effective in May 2013 and clarified the intent of EIMA on three issues: an allowed return on ComEd’s pension asset; the use of year-end rather than average rate base and capital structure in the annual reconciliation; and the use of ComEd’s weighted average cost of capital interest rate rather than a short-term debt rate to apply to the annual reconciliation. The rate increase was set using an allowed return on capital of 6.94% (inclusive of an allowed return on common equity of 8.72%). The rates took effect in January 2014. ComEd requested a rehearing on specific issues, which was denied by the ICC. ComEd also filed an appeal, which was subsequently withdrawn.

2012 Filing. On April 30, 2012, ComEd filed its annual distribution formula rate. On December 20, 2012, the ICC, issued its final order, which increased the revenue requirement by $73 million, reflecting an increase of $80 million for the initial revenue requirement for 2012 and a decrease of $7 million for the annual reconciliation for 2011. The rate increase was set using an allowed return on capital of 7.54% (inclusive of an allowed return on common equity of 9.81%). The rates took effect in January 2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appeals with the Illinois Appellate Court. The Illinois Appellate Court upheld the ICC’s decision on the issues on appeal. On May 30, 2013, ComEd updated its revenue requirement allowed in the December 2012 Order to reflect the impacts of Senate Bill 9, which resulted in a reduction to the current revenue requirement in effect of $14 million. The rates took effect in July 2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appeals with the Illinois Appellate Court. The Illinois Appellate Court reaffirmed the ICC’s order.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Formula Rate Structure Investigation

In October 2013, the ICC opened an investigation (the Investigation), in response to a complaint filed by the Illinois Attorney General, to change the formula rate structure by requesting three changes: the elimination of the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance, the netting of associated accumulated deferred income taxes against the annual reconciliation balance in calculating interest, and the use of average rather than year-end rate base for determining any ROE collar adjustment. On November 26, 2013, the ICC issued its final order in the Investigation, rejecting two of the proposed changes but accepting the proposed change to eliminate the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance. The accepted change became effective in January 2014, and reduced ComEd’s 2014 revenue by approximately $8 million. This change had no financial statement impact on ComEd in 2013. ComEd and intervenors requested rehearing, however all rehearing requests were denied by the ICC. ComEd and intervenors have filed appeals with the Illinois Appellate Court. ComEd cannot predict the results of any such appeals.

Appeal of Initial Formula Rate Tariff

On March 26, 2014, the Illinois Appellate Court issued an opinion with respect to ComEd’s appeal of the ICC’s order relating to ComEd’s initial formula rate tariff. The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislation and were clarified by subsequent legislation (Senate Bill 9). Therefore, only a subset of the issues originally appealed remained. The Court found against ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. The Court’s opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC’s final Order.

ComEd asked the Illinois Supreme Court to hear the issue of allocation between State and Federal regulatory jurisdictions. On June 4, 2014, ComEd filed a Petition for Leave to Appeal with the Illinois Supreme Court solely on the issue of allocation between FERC and ICC jurisdictional costs. On July 2, 2014, the ICC filed its Answer to the Petition, arguing that Supreme Court review is not necessary or appropriate. Under the procedural rules of the Illinois Supreme Court, ComEd is not allowed to reply to the ICC filing. There is no set time by which the Court must rule on the Petition. ComEd cannot predict whether the Court will grant the appeal, or if it does, the ultimate outcome.

Expenditures and Capital Investment

As part of the enactment of EIMA legislation 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 will not be recoverable through rates. These contributions began in 2012.

EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois’ electric utility infrastructure. Participating utilities are required to file an annual update on their AMI implementation progress. In March 2014, ComEd filed a petition with the ICC for approval to accelerate the deployment of AMI meters. On June 11, 2014, the ICC approved ComEd’s

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Combined Notes to Consolidated Financial Statements—(Continued)

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

accelerated deployment plan which allows for the installation of more than four million smart meters throughout ComEd’s service territory by 2018, three years in advance of the originally scheduled 2021 completion date. To date, nearly 550,000 smart meters have been installed in the Chicago area.

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. 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 electric distribution rate case became effective. In subsequent ICC proceedings, the ICC issued an order 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. However, on September 27, 2013 the Court ruled against ComEd on the accumulated depreciation issue and affirmed that ComEd owes a refund to customers of approximately $37 million, including interest. On September 18, 2014, the ICC issued an order requiring the refund to occur in November 2014, rather than the eight month period previously approved. The refund was included with the Rider AMP refund discussed below. Former ComEd customers were eligible for a refund. ComEd was fully reserved for this liability at December 31, 2013. As of December 31, 2014 ComEd had refunded substantially all amounts to customers.

Advanced Metering Program Proceeding (Exelon and ComEd). As part of ComEd’s 2007 Rate Case, the ICC approved recovery of costs associated with ComEd’s Rider SMP for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approved ComEd’s AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had no collections under Rider SMP through December 31, 2014. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of certain other costs from recovery under Rider AMP to recovery through electric distribution rates.

Several parties, including the Illinois Attorney General, appealed the ICC’s orders on Rider SMP and Rider AMP. The Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP and Rider AMP on September 30, 2010 and March 19, 2012, respectively. In both cases, the Court ruled that the ICC’s approval of the rider constituted single-issue ratemaking. ComEd filed Petitions for Leave to Appeal to the Illinois Supreme Court, which were denied.

In October 2013, the ICC opened an investigation on Rider AMP to determine if a refund is required and if so, to determine the appropriate refund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, which were submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount they claim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP. During the second quarter of 2014, ComEd reached a tentative agreement to jointly resolve the disputed refund claim. On September 18, 2014, the ICC approved a refund of $9.5 million

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Combined Notes to Consolidated Financial Statements—(Continued)

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

plus interest to be issued to current customers in November 2014. Former ComEd customers also were eligible for a refund. As of December 31, 2014 ComEd had refunded substantially all amounts to customers.

Grand Prairie Gateway Transmission Line (ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. On October 22, 2014, the ICC issued an order approving ComEd’s Grand Prairie Gateway Project over the objection of numerous landowners and the City of Elgin. Four parties filed timely applications for rehearing before the ICC. On November 25, 2014, the ICC denied the rehearing application filed by the Forest Preserve District of Kane County, but granted rehearing on the application of certain landowners who requested that the ICC consider an alternate route for a three-mile segment of the line in Kane County. The rehearing proceeding is currently pending and the ICC must enter a final order on rehearing by April 24, 2015. On December 10, 2014, the ICC denied the remaining two applications for rehearing. On January 15, 2015, those two parties, the City of Elgin and the SKP landowner group and Utility Risk Management Corporation (collectively, the SKP/URMC party), each filed a Notice of Appeal with the Second District Appellate Court. On February 3, 2015, the ICC filed motions with the Second District Appellate Court seeking to extend the time for the ICC to file the record on appeal until after the ICC issues its Order on rehearing. The ICC also filed a motion to consolidate those appeals. ComEd expects to begin construction of the line in the second quarter of 2015 with an in-service date expected in the second quarter of 2017.

Utility Consolidated Billing and Purchase of Receivables (Exelon and ComEd). ComEd is 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, 2014, the balance of purchased accounts receivable was $139 million. ComEd recovers from RES and customers the costs for implementing and operating the program under an ICC approved tariff. A number of municipalities, including the City of Chicago have switched to RES electric supply. As a result, ComEd experienced a significant increase in the amount of RES receivables it purchased in 2013.

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, 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.

ComEd is required to purchase an increasing percentage of the electricity for customer deliveries from renewable energy resources. Purchases by customers of electricity from competitive generation suppliers, whether as a result of the customers’ own actions or as a result of municipal aggregation, are not included in this calculation and have the effect of reducing ComEd’s purchase obligation.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd entered into several 20-year contracts with unaffiliated suppliers in December 2010 regarding the procurement of long-term renewable energy and associated RECs in order to meet its obligations under the state’s RPS. All associated costs are recoverable from customers.

On December 18, 2013, the ICC approved the IPA’s 2014-2019 procurement plan, which provided for two separate energy procurements during 2014 to address potential fluctuations in energy due to customers switching between ComEd and competitive electric generation suppliers. During May and September 2014, ComEd conducted energy procurements to meet the IPA’s 2014-2019 procurement plan. On December 17, 2014, the ICC approved the IPA’s 2015-2020 procurement plan. See Note 22—Commitments and Contingencies for additional information on ComEd’s energy commitments.

FutureGen Industrial Alliance, Inc (Exelon and ComEd). During 2013, the ICC approved, and directed ComEd and Ameren (the Utilities) to enter into 20-year 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 sourcing agreement provides that ComEd and Ameren will pay FutureGen’s contract prices, which are set annually pursuant to a formula rate. The contract prices are based on the difference between the costs of the facility and the revenues FutureGen receives from selling capacity and energy from the unit into the MISO or other markets, as well as any other revenue FutureGen receives from the operation of the facility. The order also directs ComEd and Ameren to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from ComEd or Ameren, or from competitive electric generation suppliers.

In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. On July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electric generation suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. A decision from the Illinois Appellate Court is expected in late 2015.

A significant portion of the cost of the development of FutureGen was being funded by the DOE under the American Recovery and Reinvestment Act of 2009. In early February 2015, the DOE suspended funding for the project until further clarity could be obtained on certain significant hurdles facing the project, including the outcome of the litigation described above. Whether or not the DOE funding will be reinstated at some later date is unknown at this time.

ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014. Depending on eventual market conditions and the cost of the facility, the sourcing agreement could have a material adverse impact on Exelon’s and ComEd’s cash flows and financial positions.

See Note 22—Commitments and Contingencies for additional information on ComEd’s energy commitments.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). 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 January 2014, the ICC approved ComEd’s third three-year Energy Efficiency and Demand Response Plan covering the period June 2014 through May 2017. The plans are designed to meet Illinois’ energy efficiency and demand response goals through May 2017, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers.

Illinois utilities are 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 by Illinois legislation. As of December 31, 2014, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois 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 22—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

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 have been reflected in customer bills since January 1, 2013. PECO currently anticipates that the IRS will issue guidance during 2015 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 14—Income Taxes 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.

Pennsylvania Procurement Proceedings (Exelon and PECO). PECO’s first PAPUC approved DSP Program, under which PECO was providing default electric service, had a 29-month term that ended 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.

In the second DSP Program, PECO procured electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contracts of two years or less. For the large commercial and industrial class load, PECO has competitively procured 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. PECO entered into contracts with PAPUC approved bidders, including Generation, for its five competitive procurements. 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 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 submit a plan to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning in April 2014. On May 1, 2013,

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Combined Notes to Consolidated Financial Statements—(Continued)

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PECO filed its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, the Office of Consumer Advocate (OCA) and low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court’s review, PECO will not implement CAP Shopping. The Commonwealth Court’s decision is expected in 2015.

On March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. On August 28, 2014, PECO filed a Joint Petition for Partial Settlement, which affirmed PECO’s procurement plan for Residential and Small Commercial customers. On December 4, 2014, the PAPUC approved PECO’s third DSP Program, as modified by the Joint Petition for Partial Settlement, without modification or limitation. Separate from the Joint Petition for Partial Settlement, the PAPUC also approved other items related to the program. The plan outlines how PECO will purchase electric supply for default service customers. PECO will procure electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load.

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 electric smart meters and an AMI communication network by 2020. The first phase of PECO’s SMPIP, which was completed on June 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC which was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO’s universal deployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO’s SMPIP, under which PECO will deploy all of the remaining smart meters, for a total of 1.7 million smart meters, on an accelerated basis by the second quarter of 2015. In total, PECO currently expects to spend up to $583 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $155 million on smart grid investments through final deployment of which $200 million has been funded by SGIG as discussed below. As of December 31, 2014, PECO has spent $540 million and $119 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received.

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 were used by PECO to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of the third quarter of 2014, PECO received all of the $200 million, including $4 million for sub-recipients, in reimbursements. On October 15, 2014, the DOE issued a Close Out of Post-Award Project Cost Verification Audit, in which it was determined that PECO fully met its required cost share, and the audit was closed with no further action required.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 is moving 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 $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million of depreciation. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any agreement with the vendor will not be considered project income. In addition, PECO remained eligible for the full $200 million in SGIG funds. On August 15, 2013, PECO entered into an agreement with the original vendor, which was part of the final agreement discussed below, under which PECO transferred the original uninstalled meters to the vendor and will receive $12 million in return. On January 23, 2014, PECO entered a final agreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation and removal costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously had intended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed such costs were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatory asset was established at the time of the removals. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which has been fully collected, with no gain or loss impacts on future results of operations. On March 14, 2014, PECO filed its quarterly smart meter recovery surcharge with the PAPUC which included PECO’s proposed treatment of the final agreement with the vendor. On March 27, 2014, the PAPUC approved the surcharge as proposed by PECO.

Energy Efficiency Programs (Exelon and PECO). PECO’s PAPUC-approved Phase I EE&C Plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I plan set forth how PECO would meet the required reduction targets established by Act 129’s EE&C provisions, which included 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.

The peak demand period ended on September 30, 2012 and PECO communicated its compliance with the reduction targets in a preliminary filing with the PAPUC on March 1, 2013. The final compliance report for all Phase I targets, was filed with the PAPUC on November 15, 2013.

On March 29, 2013, PECO filed a Petition with the PAPUC to change the recovery period of certain Direct Load Control (DLC) Program costs necessary to implement the Phase I Plan. The Petition sought approval to allow PECO to recover $12 million in equipment, installation and information technology costs for its Residential DLC program with the amounts collected for the Phase I Plan. As the Phase I Plan was implemented at a cost less than originally budgeted, PECO proposed to recover these expenses from its Phase I Energy Efficiency Program Charge over-

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Combined Notes to Consolidated Financial Statements—(Continued)

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

collection consistent with PAPUC guidance to recover all Phase I costs through Phase I funding. The PAPUC approved PECO’s Petition on May 9, 2013. A regulatory liability was established for the DLC program costs that will be amortized as a credit to the income statement to offset the related depreciation expense during the same period.

The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provides energy consumption reduction requirements for the second phase of Act 129’s EE&C programs, which went into effect on June 1, 2013. The order tentatively established PECO’s three-year cumulative consumption reduction target at 1,125,852 MWh, which was reaffirmed by the PAPUC on December 5, 2012.

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 1,125,852 MWh 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.

On March 15, 2013, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2013 to May 31, 2014. PECO proposed to fund the estimated $10 million costs of the one-year program by modifying incentive levels for other Phase II programs. On May 9, 2013, the PAPUC approved PECO’s amended EE&C Phase II plan. The costs of DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with all other Phase II Plan costs.

On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposed demand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale prices suppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO’s EE&C Plan subsequent to its Phase II Plan.

On February 28, 2014, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO’s Petition. The Order became final on May 5, 2014.

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

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

All AEPS administrative costs and costs of AECs are being recovered on a full and current basis from default service customers through a surcharge.

PECO’s second DSP Program eliminated the AEPS surcharge. Beginning in June 2013, AEPS compliance costs are being recovered through the GSA.

Pennsylvania Retail Electricity and Gas Markets (Exelon and PECO). Beginning in 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania’s retail electricity 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. Through various orders, the PAPUC issued default electric service pricing for customers in PECO’s service territory. See Pennsylvania procurement proceedings discussed above for additional details.

In early 2014, the extreme weather in PECO’s service territory resulted in increased electricity commodity costs causing certain shopping customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, on April 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electric generation suppliers to provide more consumer education regarding their contract. The second rulemaking order requires electric distribution companies to enable customers to switch suppliers within three business days (known as accelerated switching). The improved customer education and accelerated switching were to be in place within 30 days and six months of approval of the orders, respectively. The orders became final on June 14, 2014. On December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on Supplier Switch), allowing PECO to implement accelerated switching by the December 15, 2014 deadline.

On September 12, 2013, the PAPUC issued an Order that initiated an investigation into Pennsylvania’s natural gas retail market, including the role of the existing default service model and opportunities for market enhancements. On December 18, 2014, the PAPUC issued a Final Order directing the Office of Competitive Market Oversight to continue its investigation, confirming that natural gas distribution companies should remain with the default service model for the time being and directing establishment of a working group to examine other competitive issues. Comments on the Final Order were due on February 2, 2015. PECO will continue to monitor the Order and assess compliance, as necessary.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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. On May 9, 2013, the PAPUC approved PECO’s LTIIP for its gas operations, which was filed on February 8, 2013. On February 5, 2015, PECO filed a petition to modify its approved Gas LTIIP with the PAPUC. If approved, the modification would allow PECO to further accelerate the replacement of existing gas mains and also included a plan for the relocation of meters from indoors to outside in accordance with a recent PAPUC rulemaking.

Maryland Regulatory Matters

2014 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 2, 2014, and as amended on September 15, 2014, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $99 million and $68 million, respectively.

On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement (the Settlement Agreement) reached with all parties to the case under which it would receive an increase of $22 million in electric base rates and an increase of $38 million in gas base rates. The Settlement Agreement establishes new depreciation rates which have the effect of decreasing annual depreciation expense by approximately $20 million, primarily for electric. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreement without modification, which became a final order on December 12, 2014. The approved distribution rate order authorizing BGE to increase electric and gas distribution rates became effective for services rendered on or after December 15, 2014.

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $83 million and $24 million, respectively. In addition to these requested rate increases, BGE’s application includes a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the “ERI initiative”) in response to a MDPSC order through a surcharge separate from base rates.

On December 13, 2013, the MDPSC issued an order in BGE’s 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. Rates became effective for services rendered on or after December 13, 2013. The MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed

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Combined Notes to Consolidated Financial Statements—(Continued)

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

for completion in 2014 as part of the ERI initiative. The ERI initiative surcharge became effective June 1, 2014. On November 3, 2014, BGE filed a surcharge update including a true-up of cost estimates included in the 2014 surcharge, along with its work plan and cost estimates for 2015, to be included in the 2015 surcharge. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2014 annual report, 2015 work plan and the 2015 surcharge.

In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE’s 2013 electric and gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC’s approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing was held on November 17, 2014. BGE cannot predict the outcome of this appeal. If the residential consumer advocate’s appeal is successful, BGE could recover ERI expenditures through other regulatory mechanisms.

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. On February 22, 2013, the MDPSC issued an order for increases in annual distribution service revenue of $81 million and $32 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. The rates became effective for services rendered on or after February 23, 2013. As part of the rate order, the MDPSC approved both recovery of and return on the merger integration costs, including severance, incurred during the test year for the Exelon and Constellation merger. As a result, the order affirmed the treatment of $20 million of severance-related costs that BGE had recorded as a regulatory asset in 2012, consistent with prior MDPSC decisions. Additionally, BGE established a new regulatory asset of $8 million related to non-severance merger integration costs, which includes $6 million of costs incurred during 2012. Current MDPSC treatment of these merger integration regulatory assets is to provide recovery over a five year period.

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. 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 included the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million was recovered through a grant from the DOE. 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. As of December 31, 2014 and December 31, 2013, BGE recorded a regulatory asset of $128 million and $66 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE’s 2014 electric and gas distribution rate case discussed above, the cost of the retired non-AMI meters will be amortized over 10 years.

On February 26, 2014, the MDPSC issued an order authorizing BGE to impose a $75 upfront fee and an $11 recurring fee to customers electing to opt-out of BGE’s smart meter installation program,

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Combined Notes to Consolidated Financial Statements—(Continued)

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

effective the later of the first full billing cycle following July 1, 2014, or the AMI installation date in a customer’s community. The fees authorized by the order will be reviewed after an initial 12 to 18 month period. On November 25, 2014, the MDPSC issued a decision approving BGE’s proposal to automatically enroll unresponsive customers into the opt-out program and to charge those customers opt-out fees after BGE has exhausted attempts to schedule a meter installation. The ultimate impact of opt-out could affect BGE’s ability to demonstrate cost-effectiveness of the advanced metering system.

Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs.

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 700MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that CPV projected will be in commercial operation by June 1, 2015. The initial term of the proposed contract is 20 years. The CfD mandates that BGE and the other 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 MDPSC’s order requires the three Maryland utilities to enter into a CfD in amounts proportionate to their relative SOS load.

On April 16, 2013, the MDPSC issued an order that required BGE to execute a specific form of contract with CPV, and the parties executed the contract as of June 6, 2013. As of December 31, 2014, there is no impact on Exelon’s and BGE’s results of operations, cash flows and financial positions. Furthermore, the agreement does not become effective until the resolution of certain items, including all current litigation.

On April 27, 2012, a civil complaint was filed in the U.S. District Court for the District of Maryland by certain unaffiliated parties that challenged the actions taken by the MDPSC on Federal law grounds. On October 24, 2013, the U.S. District Court issued a judgment order finding that the MDPSC’s Order directing BGE and the two other Maryland utilities to enter into a CfD, which assures that CPV receives a guaranteed fixed price regardless of the price set by the federally regulated wholesale market, violates the Supremacy Clause of the United States Constitution. On November 22, 2013, the MDPSC and CPV appealed the District Court’s ruling to the United States Court of Appeals for the Fourth Circuit.

On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order under state law. That petition was subsequently transferred to the Circuit Court for Baltimore City and consolidated with similar appeals that have been filed by other interested parties. On October 1, 2013, the Circuit Court Judge issued a Memorandum Opinion and Order finding the decisions of the MDPSC were within its statutory authority under Maryland law. This decision is separate from the judgment in the federal litigation that the MDPSC Order is unconstitutional and the CfD is unenforceable under federal law. The federal judgment, if upheld, would prevent enforcement of the CfD even if the Circuit Court decision stands. On October 29, 2013, BGE and the two other Maryland utilities appealed the Circuit Court’s ruling to the Maryland Court of Special Appeals.

Depending on the ultimate outcome of the pending state and federal litigation, on the eventual market conditions, and on the manner of cost recovery as of the effective date of the agreement, the CfD could have a material impact on Exelon and BGE’s results of operations, cash flows and financial positions.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon believes that this and other states’ projects may have artificially suppressed capacity prices in PJM and may continue to do so in future auctions to the detriment of Exelon’s market driven position. In addition to this litigation, Exelon is working with other market participants to implement market rules that will appropriately limit the market suppressing effect of such state activities.

MDPSC Derecho Storm Order (Exelon and BGE). Following the June 2012 Derecho storm which hit the mid-Atlantic region interrupting electrical service to a significant portion of the State of Maryland, the MDPSC issued an order on February 27, 2013 requiring BGE and other Maryland utilities to file several comprehensive reports with short-term and long-term plans to improve reliability and grid resiliency that were due at various times before August 30, 2013.

On September 3, 2013, BGE filed a comprehensive long term assessment examining potential alternatives for improving the resiliency of the electric grid and a staffing analysis reviewing historical staffing levels as well as forecasting staffing levels necessary under various storm scenarios. During the summer of 2014, an evaluation of the reports filed by BGE and other Maryland utilities was undertaken by consultants on behalf of the MDPSC and MDPSC Staff. The MDPSC Staff also proposed standards for reliability during major events and estimated times of restoration as well as undertaking an evaluation of performance-based ratemaking principles and methodologies that would more directly and transparently align reliable service with the utilities’ distribution rates and that reduce returns or otherwise penalize sub-standard performance. The MDPSC held hearings in September 2014. BGE currently cannot predict the outcome of these proceedings, which may result in increased capital expenditures and operating costs.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On March 26, 2014, the Maryland PSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. On November 17, 2014, BGE filed a surcharge update including a true-up of costs estimates included in the 2014 surcharge, along with its 2015 project list and cost estimates to be included in the 2015 surcharge. The filing was approved with a revised surcharge effective January 1, 2015. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2015 project list and the proposed surcharge for 2015. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial to Exelon and BGE as of December 31, 2014.

In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE’s infrastructure replacement

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Combined Notes to Consolidated Financial Statements—(Continued)

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

plan. On September 5, 2014, the Baltimore City Circuit Court affirmed the MDPSC decision on BGE’s infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court, however, a procedural schedule for the matter has not yet been set.

New York Regulatory Matters

Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). Ginna Nuclear Power Plant’s (Ginna) prior period fixed-price PPA contract with Rochester Gas & Electric Company (RG&E) expired in June 2014. In light of the expiration of the agreement, Ginna advised the New York Public Service Commission (NYPSC) and ISO-NY that in absence of a reliability need, Ginna management would make a recommendation, subject to approval by the CENG board, that Ginna be retired as soon as practicable. A formal study conducted by the ISO-NY and RG&E concluded that the Ginna nuclear plant needs to remain in operation to maintain the reliability of the transmission grid in the Rochester region through 2018 when planned transmission system upgrades are expected to be completed. In November, in response to a petition filed by Ginna, the NYPSC directed Ginna and RG&E to negotiate a Reliability Support Services Agreement (RSSA). On February 13, 2015, regulatory filings, including RSSA terms negotiated between Ginna and RG&E, to support the continued operation of Ginna for reliability purposes were made with the NYPSC and with FERC for their approval. While the RSSA is expected to be approved, in absence of such an agreement and in the event the plant was retired before the current license term ends in 2029, Exelon’s and Generation’s results of operations could be adversely affected by increased depreciation rates, impairment charges, severance costs, and accelerated future decommissioning costs, among other items. However, it is not expected that such impacts would be material to Exelon’s or Generation’s results of operations.

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 and BGE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s and BGE’s best estimate of the revenue requirement expected to be approved by the FERC for that year’s reconciliation. As of December 31, 2014, and 2013, ComEd had a regulatory asset associated with the transmission formula rate of $21 million and $17 million, respectively, and BGE had a net regulatory asset associated with the transmission formula rate of $1 million and a net regulatory liability which was not material as of December 31, 2013. The regulatory asset associated with transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates.

In April 2014, ComEd filed its annual 2014 formula rate update with the FERC, reflecting an increased revenue requirement of $22 million, including an increase of $36 million for the initial revenue requirement, offset by a decrease of $14 million related to the annual reconciliation. The filing established the revenue requirement used to set rates that took effect in June 2014. ComEd’s 2014

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Combined Notes to Consolidated Financial Statements—(Continued)

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

formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.62%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. The time period for any challenges to ComEd’s annual 2014 formula rate update expired in October 2014 with no challenges submitted.

In April 2013, ComEd filed its annual 2013 formula rate update with the FERC, reflecting an increased revenue requirement of $68 million, including an increase of $38 million for the initial revenue requirement and an increase of $30 million related to the annual reconciliation. The filing established the revenue requirement used to set rates that took effect in June 2013. ComEd’s 2013 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.70%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.91% average debt and equity return previously authorized. The time period for any challenges to ComEd’s annual 2013 formula rate update expired in October 2013 with no challenges submitted.

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%.

In April 2014, BGE filed its 2014 formula rate update with the FERC reflecting an increased revenue requirement of $14 million, including an increase of $9 million for the initial revenue requirement and an increase of $5 million related to the annual reconciliation. The annual update established the revenue requirement used to set rates that took effect in June 2014. The time period for any challenges to BGE’s annual update expired in October 2014 with no challenges submitted.

BGE’s 2014 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.53%, an increase from the 8.35% average debt and equity return previously authorized. As part of the FERC-approved settlement of BGE’s 2005 transmission rate case in 2006, the rate of return on common equity for BGE’s electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.3%, inclusive of a 50 basis point incentive for participating in PJM.

FERC Transmission Complaint (Exelon and BGE). On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the Pepco Holdings, Inc. companies relating to their respective transmission formula rates. BGE’s formula rate includes a 10.8% base rate of return on common equity (ROE) and a 50 basis point incentive for participating in PJM (the latter of which is conditioned upon crediting the first 50 basis points of any incentive ROE adders). The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint.

282

Combined Notes to Consolidated Financial Statements—(Continued)

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

Settlement Judge informed FERC and the Chief Judge that the parties had reached an impasse and determined that a settlement was not possible. On November 26, 2014, the Chief Judge issued an order terminating the settlement proceeding, designating a presiding judge at the hearings and directing that an initial decision be issued by November 25, 2015.

On December 8, 2014, various state agencies in Delaware, Maryland, New Jersey, and D.C. filed a second complaint against BGE regarding the base ROE of the transmission business seeking a reduction from 10.8% to 8.8%. The filing of the second complaint creates a second refund window. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants’ requested refund effective date of December 8, 2014.

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 from those facilities. 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 March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order. On March 22, 2013, FERC issued an order denying rehearing and made it clear that the cost allocation at issue concerns only projects approved prior to February 1, 2013. A number of entities have filed appeals of the FERC orders. On June 25, 2014, the U.S. Court of Appeals for the Seventh Circuit issued a decision once again remanding to FERC the cost allocation of new facilities 500 kV and above. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the issue of the cost allocation for facilities 500 kV and above. The hearing only concerns new facilities approved

283

Combined Notes to Consolidated Financial Statements—(Continued)

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

by the PJM Board prior to February 1, 2013. 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.

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		2015		2016		2017		2018		2019
ComEd	$	335	$	150	$	172	$	5	$	4	$	4
PECO		100		32		31		25		8		4
BGE		351		77		104		77		57		36

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 FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014.

Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts and capacity market speculators) cannot inappropriately affect capacity auction prices in PJM.

Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE). On May 23, 2014, the D.C. Circuit Court issued an opinion vacating the FERC Order No. 745 (“D.C. Circuit Decision”). Order No. 745 established uniform compensation levels for demand response resources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets were required to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and was cost-effective.

In addition to invalidating the compensation structure established by Order No. 745, the D.C. Circuit Court, in broad language, explained that demand response is part of the retail market and FERC is restricted from regulating retail markets. The full implication of the D.C. Circuit Decision for both energy and capacity markets regulated by FERC is not yet known and will depend on how FERC and the RTOs and ISOs implement the decision. FERC and several other parties sought rehearing of the D.C. Circuit Decision, which was denied in September 2014. In addition, on September 22, 2014, FERC and another party sought to stay the issuance of the D.C. Circuit Court’s mandate so that FERC may appeal the decision to the U.S. Supreme Court. The stay was granted with respect to the FERC’s request only. In January 2015, the FERC sought to appeal the decision to the U.S. Supreme Court.

284

Combined Notes to Consolidated Financial Statements—(Continued)

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

Thus, the stay will be extended at least until the U.S. Supreme Court determines whether to allow the appeal. In addition, contemporaneously with the D.C. Circuit Court’s decision on May 23, 2014, First Energy filed a complaint at FERC asking FERC to direct PJM to remove all PJM Tariff provisions that allow or require PJM to compensate demand response providers as a form of supply in the PJM capacity market effective May 23, 2014. FirstEnergy also asked FERC to declare the results of PJM’s May 2014 Base Residual Auction for the 2017/2018 Delivery Year, void and illegal to the extent that demand response resources cleared that auction. On November 14, 2014, the New England Power Generators Association, Inc. (“NEPGA”) filed a similar complaint at FERC asking FERC to disqualify demand response from the upcoming capacity auction in New England and to revise the New England tariff to remove demand response from participation in the capacity market. FERC’s response to the FirstEnergy complaint and the NEPGA complaint and its response to address the D.C. Circuit Court’s decision in all markets could preclude demand response resources from receiving any future capacity market revenues and also subject such resources to refund obligations. In addition, there is uncertainty as to how FERC might treat already settled capacity market auctions as well as future auctions, both for demand response resources and generation resources. FERC could grant all or a portion of the relief requested by FirstEnergy and may grant relief retroactively or only prospectively. FERC could also pursue alternative means for allowing demand response to effectively participate in capacity markets it regulates. Due to these uncertainties, the Registrants are unable to predict the outcome of these proceedings, and the final outcome is not expected for several months. Nonetheless, the final decision and its implementation by FERC and the RTOs and ISOs, could be material to Exelon, Generation, ComEd, PECO and BGE’s results of operations and cash flows.

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 file 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, capacity, and ancillary services under market-based rate tariffs. On June 29, 2012, Generation, ComEd, PECO and BGE filed their updated market power analysis for the Central Region which the FERC accepted on November 13, 2012. On December 21, 2012, Generation, ComEd, PECO, and BGE filed their updated market power analysis for the SPP region, which the FERC accepted on October 8, 2013. On December 30, 2013, Generation, ComEd, PECO and BGE filed its updated analysis for the Northeast Region, based on 2012 historic test period data which the FERC accepted on August 5, 2014. On December 23, 2014, Generation filed its updated market power analysis for the Southeast Region and the FERC has not yet acted on the filing.

Reliability Pricing Model (Exelon, Generation and BGE). PJM’s RPM Base Residual Auctions take place approximately 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2018 occurred in May 2014.

285

Combined Notes to Consolidated Financial Statements—(Continued)

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

New England Capacity Market Results (Exelon and Generation). Each year, ISO New England, Inc. (ISO-NE) files the results of its annual capacity auction at the FERC which is required to include documentation regarding the competitiveness of the auction. Consistent with this requirement, on February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 30, 2018 delivery period). On June 27, 2014, the FERC issued a letter to ISO-NE noting that ISO-NE’s February 28, 2014 filing was deficient and that ISO-NE must file additional information before the FERC can process the filing. ISO-NE filed the information on July 17, 2014, and the ISO-NE’s filings became effective by operation of law pursuant to a notice issued by the FERC’s secretary on September 16, 2014. Several parties sought rehearing of the secretary’s notice which was effectively denied in October 2014 and have since appealed the matter to the U.S. D.C. Circuit Court of Appeals. It is not clear whether such appeal would be effective as there is no action by the Commission to be considered. Nonetheless, while we think any change in the auction results to be unlikely, Exelon and Generation cannot predict with certainty what further action the court may take concerning the results of that auction, but any court action could be material to Exelon’s and Generation’s expected revenues from the capacity auction.

License Renewals (Exelon and Generation). In June 2012, the United States 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”) recognized 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. On August 26, 2014, the NRC Commissioners approved the issuance of a revised rule codifying the NRC’s generic determinations regarding the environmental impacts of continued storage of spent nuclear fuel beyond a reactor’s licensed operating life and removed the hold on final licensing decision as of the effective date of the final rule. On September 19, 2014, the NRC issued the Continued Storage Rule, which became effective on October 20, 2014. On October 24, 2014, New York, Vermont, and Connecticut filed a petition for review in federal court which alleges that the Continued Storage Rule violates various federal laws and regulations. The petition additionally challenges the Continued Storage Rule’s supporting generic environmental impact statement (GEIS) as well as the August 26, 2014 NRC order lifting the suspension of all final licensing decisions for affected applications in view of the rule and GEIS.

On May 29, 2013, Generation submitted applications to the NRC to extend the current operating licenses of Byron Units 1 and 2, which are currently set to expire in 2024 and 2026, respectively, and Braidwood Units 1 and 2, currently set to expire in 2026 and 2027, respectively, by 20 years. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until late 2015 at the earliest.

On October 20, 2014, the NRC approved Generation’s request to extend the operating licenses of Limerick Units 1 and 2 by 20 years to 2044 and 2049, respectively.

On December 9, 2014, Generation submitted applications to the NRC to extend the operating licenses of LaSalle Units 1 and 2 by 20 years, which are currently set to expire in 2022 and 2023, respectively. Generation does not expect the NRC to issue license renewals for LaSalle until 2016 at the earliest.

286

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively.

Generation is working with stakeholders to resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Generation filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed. MDE indicated that it believed it did not have sufficient information to process Generation’s application. As a result, on December 5, 2014, Generation withdrew its pending application for a water quality certification. FERC policy requires that an applicant resubmit its request for a water quality certification within 90 days of the date of withdrawal. Accordingly, Generation is working with MDE to coordinate the refiling of its application for certification within the 90-day period. In addition, Generation has entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake Bay Program to design, conduct and fund an additional multi-year sediment study. Exelon has agreed to contribute up to $3.5 million to fund the additional study. Resolution of these issues relating to Conowingo may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.

On June 3, 2014, subsequently amended December 9, 2014, the PA DEP issued its water quality certificate for Muddy Run, which is a necessary step in the FERC licensing process and included certain commitments made by Generation. The financial impact associated with these commitments is estimated to be in the range of $25 million to $35 million, and will include both capital expenditures and operating expenses, primarily relating to fish passage and habitat improvement projects.

The FERC licenses for Muddy Run and Conowingo were set to expire on August 31, 2014 and September 1, 2014 respectively. FERC is required to issue annual licenses for the facilities until the new licenses are issued. On September 10, 2014, FERC issued annual licenses for Conowingo and Muddy Run, effective as of the expiration of the previous licenses. If FERC does not issue new licenses prior to the expiration of annual licenses, the annual licenses will renew automatically. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of December 31, 2014, $39 million of direct costs associated with licensing efforts have been capitalized.

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.

287

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2014 and 2013.


December 31, 2014	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	247	$	3,009	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes		6		1,536		—		64		—		1,400		6		72
AMI programs		25		271		10		81		15		62		—		128
Under-recovered distribution service costs		251		120		251		120		—		—		—		—
Debt costs		8		49		6		47		2		2		1		8
Fair value of BGE long-term debt		7		183		—		—		—		—		—		—
Severance		4		8		—		—		—		—		4		8
Asset retirement obligations		1		115		1		73		—		26		—		16
MGP remediation costs		36		221		30		189		6		31		—		1
Under-recovered uncollectible accounts		—		67		—		67		—		—		—		—
Renewable energy		20		187		20		187		—		—		—		—
Energy and transmission programs		37		11		26		7		—		—		11		4
Deferred storm costs		1		2		—		—		—		—		1		2
Electric generation-related regulatory asset		10		20		—		—		—		—		10		20
Rate stabilization deferral		75		85		—		—		—		—		75		85
Energy efficiency and demand response programs		89		159		—		—		—		—		89		159
Merger integration costs		2		6		—		—		—		—		2		6
Conservation voltage reduction		1		1		—		—		—		—		1		1
Under-recovered electric revenue decoupling		7		—						—		—		7		—
Other ^(a)		20		26		5		17		6		8		7		—

Total regulatory assets	$	847	$	6,076	$	349	$	852	$	29	$	1,529	$	214	$	510


December 31, 2014	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory liabilities
Other postretirement benefits	$	51	$	37	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning		—		2,879		—		2,389		—		490		—		—
Removal costs		118		1,448		94		1,249		—		—		24		199
Energy efficiency and demand response programs		25		2		25		—		—		2		—		—
DLC program costs		—		10		—		—		—		10		—		—
Energy efficiency phase II		—		32		—		—		—		32		—		—
Electric distribution tax repairs		8		94		—		—		8		94		—		—
Gas distribution tax repairs		20		29		—		—		20		29		—		—
Energy and transmission programs		68		16		3		16		58		—		7		—
Over-recovered electric universal service fund costs		2		—		—		—		2		—		—		—
Revenue subject to refund		3		—		3		—		—		—		—		—
Over-recovered gas revenue decoupling		12		—		—		—		—		—		12		—
Other		3		3		—		1		2		—		1		1

Total regulatory liabilities	$	310	$	4,550	$	125	$	3,655	$	90	$	657	$	44	$	200

288

Combined Notes to Consolidated Financial Statements—(Continued)

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


December 31, 2013	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	221	$	2,794	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes		10		1,459		2		65		—		1,317		8		77
AMI programs		5		159		5		35		—		58		—		66
AMI meter events		—		5		—		—		—		5		—		—
Under-recovered distribution service costs		178		285		178		285		—		—		—		—
Debt costs		12		56		9		53		3		3		1		8
Fair value of BGE long-term debt		—		219		—		—		—		—		—		—
Fair value of BGE supply contracts		12		—		—		—		—		—		—		—
Severance		16		12		12		—		—		—		4		12
Asset retirement obligations		1		102		1		67		—		25		—		10
MGP remediation costs		40		212		33		178		6		33		1		1
RTO start-up costs		2		—		2		—		—		—		—		—
Under-recovered uncollectible accounts		—		48		—		48		—		—		—		—
Renewable energy		17		176		17		176		—		—		—		—
Energy and transmission programs		53		9		52		6		—		—		1		3
Deferred storm costs		3		3		—		—		—		—		3		3
Electric generation-related regulatory asset		13		30		—		—		—		—		13		30
Rate stabilization deferral		71		154		—		—		—		—		71		154
Energy efficiency and demand response programs		73		148		—		—		—		—		73		148
Merger integration costs		2		9		—		—		—		—		2		9
Other ^(a)		31		30		18		20		8		7		4		3

Total regulatory assets	$	760	$	5,910	$	329	$	933	$	17	$	1,448	$	181	$	524


December 31, 2013	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory liabilities
Other postretirement benefits	$	2	$	43	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning		—		2,740		—		2,293		—		447		—		—
Removal costs		99		1,423		78		1,219		—		—		21		204
Energy efficiency and demand response programs		53		—		45		—		8		—		—		—
DLC Program Costs		1		10		—		—		1		10		—		—
Energy efficiency phase II		—		21		—		—		—		21		—		—
Electric distribution tax repairs		20		114		—		—		20		114		—		—
Gas distribution tax repairs		8		37		—		—		8		37
Energy and transmission programs		78		—		9		—		58		—		11		—
Over-recovered gas universal service fund costs		8		—		—		—		8		—		—		—
Revenue subject to refund		38		—		38		—		—		—		—		—
Over-recovered electric and gas revenue decoupling		16		—		—		—		—		—		16		—
Other		4		—		—		—		3		—		—		—

Total regulatory liabilities	$	327	$	4,388	$	170	$	3,512	$	106	$	629	$	48	$	204

(a)

For ComEd and BGE, includes Purchase of Receivable Program regulatory assets. As of December 31, 2014, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $14 million and $7 million, respectively. As of December 31, 2013, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $27 million and $0 million, respectively.

289

Combined Notes to Consolidated Financial Statements—(Continued)

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

Pension and other postretirement benefits. As of December 31, 2014, Exelon had regulatory assets of $3,256 million and regulatory liabilities of $88 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 (liability) balances. The regulatory asset (liability) is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses (gains) 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 Constellation merger related to BGE’s portion of the deferred costs associated with legacy Constellation’s pension and other postretirement benefit plans. The 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 Constellation merger. See Note 16—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 accelerated 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 was 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. For PECO, this amount includes the impacts of electric and gas distribution repairs in the deductibility pursuant to PUC’s 2010 rate case settlement agreement. See Note 14—Income Taxes and Note 16—Retirement Benefits for additional information. ComEd, PECO and BGE are not earning a return on the regulatory asset in base rates.

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 through May 31, 2014, and January 1, 2020, respectively. As of December 31, 2014 and December 31, 2013, ComEd had regulatory assets of $88 million and $35 million, respectively, related to accelerated depreciation costs resulting from the early retirements of non-AMI meters, 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 regulatory asset. 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, 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

290

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 recovery of those costs commenced with the new rates approved and implemented with the MDPSC order in BGE’s 2014 electric and gas distribution case.

AMI Meter Events. This amount represents the remaining cost value of the original smart meters, net of accumulated depreciation, DOE reimbursements and amounts recovered from the vendor, of smart meter deployment that will no longer be used, including installation and removal costs. PECO intended to seek through regulatory rate recovery in a future filing with the PAPUC, any amounts not recovered from the vendor. PECO believed the amounts incurred for the original meters and related installation and removal costs were probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As such, PECO deferred these costs on Exelon’s and PECO’s Consolidated Balance Sheet, beginning in 2012. PECO did not earn a return on the recovery of these costs. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which has been fully collected, with no gain or loss impacts on future results of operations.

Under-recovered distribution services costs. Under EIMA, 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 over recovery associated with the 2011 reconciliation was recovered through rates over a one-year period, that began in January 2013. The under recovery associated with the 2012 reconciliation was recovered through rates over a one-year period that began in January 2014. The under recovery associated with the 2013 reconciliation will be recovered through rates over a one-year period beginning in January 2015. ComEd is earning a return on these costs. 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. As of December 31, 2014, the regulatory asset was comprised of $286 million for the applicable annual reconciliations and $85 million related to significant one-time events. In addition to $66 million in deferred storm costs, net of amortization, the December 31, 2014 balance related to significant one-time events contains $19 million of Constellation merger and integration related costs, net of amortization, incurred as a result of the Constellation merger. As of December 31, 2013, the regulatory asset was comprised of $377 million for the applicable annual reconciliations and $86 million related to significant one-time events. In addition to $58 million in deferred storm costs, net of amortization, the December 31, 2013 balance related to significant one-time events contains $28 million of Constellation merger and integration related costs, net of amortization, incurred as a result of the Constellation merger. See Note 4—Mergers, Acquisitions, and Dispositions for additional information.

291

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, while PECO is earning a return on the premium of the cost of the reacquired debt through base rates.

Fair value of BGE long-term debt. These amounts represent the regulatory asset recorded at Exelon for the difference in the fair value of the long-term debt of BGE as of the Constellation merger date based on the MDPSC practice to allow BGE to recover its debt costs through rates. Exelon is amortizing the regulatory asset and the associated fair value over the life of the underlying debt and is not earning a return on the recovery of these costs.

Fair value of BGE supply contract. These amounts represent the regulatory asset recorded at Exelon representing the fair value of BGE’s supply contracts as of the close of the Constellation merger date based on the MDPSC practice to allow BGE to recover its supply contracts through rates. Exelon amortized the regulatory asset and the associated fair value through December 31, 2014 and was not earning a return on the recovery of these contracts.

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, and such costs were fully recovered as of December 31, 2014. ComEd did not earn a return on these costs. For BGE, these costs represent deferred severance costs that BGE has previously been granted recovery of in rates. 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 through December 31, 2013. 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 legally required removal costs associated with 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 and BGE will recover these costs through future depreciation rates and will earn a return on these costs once the removal activities have been performed. See Note 15—Asset Retirement Obligations for additional information.

MGP remediation costs. ComEd is allowed recovery of these costs under ICC approved rates. For PECO, these costs are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. 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. While BGE does not have a rider for MGP clean-up costs, BGE has historically received

292

Combined Notes to Consolidated Financial Statements—(Continued)

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

recovery of actual clean-up costs on a site-specific basis in distribution rates. 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 return on this regulatory asset. See Note 22—Commitments and Contingencies for additional information.

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, 2014, PECO was under-recovered for its gas program and over-recovered for its electric program. Whereas, as of December 31, 2013, PECO was over-recovered for both its electric and gas programs PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers.

Under (Over)-recovered uncollectible accounts. ComEd adjusts its rates annually to reflect the increases and decreases in annual uncollectible accounts costs. The recovery or refund of the difference in the uncollectible accounts costs takes place over a 12-month time frame beginning in June of the following year. ComEd is not earning a return or paying interest on these under (over)-recovered costs.

Renewable Energy. 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. 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.

Energy and transmission programs. 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. As of December 31, 2014, ComEd’s regulatory asset of $33 million included $4 million related to under-recovered energy costs for non-hourly customers, $22 million associated with transmission costs recoverable through its FERC-approved formulate rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2014, ComEd’s regulatory liability of $19 million included $3 million related to over-recovered energy costs for hourly customers and $16 million associated with revenues received for renewable energy requirements. As of December 31, 2013, ComEd’s regulatory asset of $58 million included $35 million related to under-recovered energy costs for hourly and non-hourly customers, $17 million associated with transmission costs recoverable through its FERC-approved formula rate, and $6 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2013, ComEd’s regulatory liability of $9 million related to revenues received for renewable energy requirements.

293

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. In addition, beginning in 2013, the deferred DSP I and II Program costs are presented on a net basis with PECO’s GSA under (over)-recovered energy costs. See discussion below of each program. 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, 2014, PECO had a regulatory liability that included $39 million related to the DSP program, $16 million related to over-recovered natural gas supply costs under the PGC and $3 million related to over-recovered electric transmission costs. As of December 31, 2013, PECO had a regulatory liability that included $34 million related to the DSP program, $8 million related the over-recovered electric transmission costs and $16 million related to over-recovered natural gas supply costs under the PGC.

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 that began 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 that began January 1, 2011. PECO earns a return on the recovery of information technology costs. These costs are included within the energy and transmission programs line item.

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 that began 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. These costs are included within the energy and transmission programs line item.

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. As of December 31, 2014, BGE’s regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE’s regulatory liability of $7 million related to over-recovered natural gas supply costs. As of December 31, 2013, BGE’s regulatory asset of $4 million included $3 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2013, BGE’s regulatory liability of $11 million related to over-recovered natural gas supply 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 return on this regulatory asset.

294

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. The portion of this regulatory asset that does not earn a regulated rate of return was $28 million as of December 31, 2014, and $37 million as of December 31, 2013. 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 2014 and 2013, BGE recovered $65 million and $66 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 Plan, PECO’s PAPUC-approved EE&C Plan, and the BGE Smart Energy Savers Program^®. ComEd recovers these costs 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. For PECO, this amount represents an over-collection of program costs related to both Phase I and Phase II of its EE&C Plan. PECO does not earn (pay) interest on under (over) collections. PECO began recovering the costs of its Phase I and Phase II EE&C Plans through a surcharge in January 2010 and June 2013, respectively, based on projected spending under the programs. Phase I recovery continued over the life of the program, which expired on May 31, 2013 and excess funds collected began being refunded in June 2013. Phase II of the program began on June 1, 2013, and will continue over the life of the program, which will expire on May 31, 2016. Excess funds collected are required to be refunded beginning in June 2016. PECO earned a return on the capital investment incurred under Phase I of the program. BGE’s Smart Energy Savers Program^® includes both MDPSC approved demand response and energy efficiency programs. For the BGE Peak Rewards^SM 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. Also included in the demand response program are customer bill credits related to BGE’s Smart Energy Rewards program which began in July 2013. 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 rate of return on the capital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections.

295

Combined Notes to Consolidated Financial Statements—(Continued)

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

Merger integration costs. These amounts represent integration costs to achieve distribution synergies related to the Constellation merger transaction. As a result of the MDPSC’s February 2013 rate order, BGE deferred $8 million related to non-severance merger integration costs incurred during 2012 and the first quarter of 2013. Of these costs, $4 million was authorized to be amortized over a 5-year period that began in March 2013. The recovery of the remaining $4 million was deferred. In the MDPSC’s December 2013 rate order, BGE was authorized to recover the remaining $4 million and an additional $4 million of non-severance merger integration costs incurred during 2013. These costs are being amortized over a 5-year period that began in December 2013. BGE is earning a return on this regulatory asset included in base rates.

Under (Over)-recovered electric and gas revenue decoupling. These amounts represent the electric and gas distribution costs recoverable from or (refundable) to customers under BGE’s decoupling mechanism, which does not earn a rate of return. As of December 31, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling.

Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs for the Regulatory Agreement Units 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 be sufficient to fund the associated future decommissioning costs at the time of decommissioning. See Note 15—Asset Retirement Obligations for additional information.

Removal costs. These amounts represent funds ComEd and BGE have received from customers through depreciation rates to cover the future non-legally required cost of removal of property, plant and equipment which reduces rate base for ratemaking purposes. This liability is reduced as costs are incurred.

DLC Program Costs. The DLC program costs include equipment, installation, and information technology costs necessary to implement the DLC Program under PECO’s EE&C Phase I Plans. PECO received full cost recovery through Phase I collections and will amortize the costs as a credit to the income statement to offset the related depreciation expense during the same period through September 2025, which is the remaining useful life of the assets. PECO is not paying interest on these over-recovered costs.

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 began being reflected in customer bills on January 1, 2013. No interest will be paid to customers.

296

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. These costs are included within the energy and transmission programs line item.

Revenue subject to refund. These amounts represent refunds and associated interest ComEd owes to customers primarily related to the treatment of the post-test year accumulated depreciation issue in the 2007 Rate Case. As of December 31, 2014, and December 31, 2013, ComEd owed $3 million and $37 million with $1 million of interest, respectively. See above discussion of the 2007 Rate Case for further information.

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 purchases receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. BGE’s tariff provides that receivables are to be purchased at a discount, primarily to recover uncollectible accounts expense from the suppliers. However, if the discount rate is negative, the tariff provides that the receivable is purchased at a zero discount rate. BGE is currently purchasing certain receivables at a zero discount rate. PECO is required to purchase receivables at face value and is 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, 2014 and 2013.


As of December 31, 2014	Exelon			ComEd			PECO			BGE
Purchased receivables^(a)	$	290		$	139		$	76		$	75
Allowance for uncollectible accounts^(b)		(42	)		(21	)		(8	)		(13	)

Purchased receivables, net	$	248		$	118		$	68		$	62


As of December 31, 2013	Exelon			ComEd			PECO			BGE
Purchased receivables^(a)	$	263		$	105		$	72		$	86
Allowance for uncollectible accounts^(b)		(30	)		(16	)		(7	)		(7	)

Purchased receivables, net	$	233		$	89		$	65		$	79

(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 and BGE, 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.

297

Combined Notes to Consolidated Financial Statements—(Continued)

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

4. Mergers, Acquisitions, and Dispositions

Proposed Merger with Pepco Holdings, Inc. (Exelon)

Description of Transaction

On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. In connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $126 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI as of December 31, 2014, with additional investments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million. The preferred securities are included in Other non-current assets on Exelon’s Consolidated Balance Sheet. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any. Exelon expects total cash required to fund the acquisition of common stock and preferred securities plus other related acquisition costs to total approximately $7.2 billion. As part of the applications for approval of the merger, Exelon and PHI proposed a package of benefits to the PHI utilities’ respective customers, providing for direct investment of more than $100 million with the actual amount and timing of any related payments dependent upon settlement discussions in merger regulatory approval proceedings and the terms of regulatory orders approving the merger.

On October 9, 2014, PHI and Exelon each received a request for additional information from the DOJ. The request had the effect of extending the DOJ review period until 30 days after PHI and Exelon each has certified that it had substantially complied with the request. On November 21, 2014, Exelon and PHI each certified that it had substantially complied with the request. Accordingly, the HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the merger, the DOJ has not advised Exelon or PHI that it has concluded its investigation. Exelon and PHI will continue to work cooperatively with the DOJ regarding the proposed merger.

Exelon and PHI continue to expect to complete the merger in the second or third quarter of 2015.

298

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin PHI from completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. In September 2014, the parties reached a proposed settlement which is subject to court approval. Final court approval of the proposed settlement is not expected to occur until the second quarter of 2015, at the earliest. Exelon has also been named in a federal court case with similar claims and is in the process of negotiating a settlement. Exelon does not believe these suits will impact the completion of the transaction, and they are not expected to have a material impact on Exelon’s results of operations.

Through December 31, 2014, Exelon has incurred approximately $179 million of expense associated with the proposed merger, primarily $48 million related to acquisition and integration costs and $131 million of costs incurred to finance the transaction. The Merger Agreement also provides for termination rights on behalf of both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the Merger Agreement does not close due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities of PHI described above, through the redemption by PHI of the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock.

Merger Financing

Exelon intends to fund the all-cash transaction using a combination of approximately $3.5 billion of debt, up to $1.0 billion in cash from asset sales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). On June 11, 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share in connection with forward sales agreements and $1.2 billion of junior subordinated notes in the form of 23 million equity units. In addition, Exelon signed a 364-day $7.2 billion senior unsecured bridge credit facility to support the contemplated transaction and provide flexibility for timing of permanent financing, which has subsequently been reduced to a $3.2 billion facility as a result of the execution of the debt and equity security issuances and the net after-tax cash proceeds from generating asset divestitures during the second half of 2014. See Note 13—Debt and Credit Agreements and Note 19—Common Stock for more information.

Acquisitions (Exelon and Generation)

Acquisition of Integrys Energy Services, Inc. (Exelon and Generation)

On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $332 million, including net working capital. Generation has elected to account for the transaction as an asset acquisition for federal income tax purposes. As of December 31, 2014, Generation had remitted $319 million to Integrys Energy Group, Inc. and the remaining balance of $13 million, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets, will be paid during the first or second quarter of 2015. The generation and solar asset businesses of Integrys are excluded from the transaction. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature.

299

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the Integrys acquisition by Generation:


Total consideration transferred	$	332

Identifiable assets acquired and liabilities assumed
Working capital assets	$	389
Mark-to-market derivative assets		185
Unamortized energy contract assets		115
Customer relationships		48
Working capital liabilities		(195	)
Mark-to-market derivative liabilities		(57	)
Unamortized energy contract liabilities		(109	)
Deferred tax liability		(16	)

Total net identifiable assets, at fair value	$	360

Bargain purchase gain (after-tax)	$	28

The purchase accounting is preliminary, and although not expected, may be further adjusted from what is shown above.

The after-tax bargain purchase gain of $28 million is primarily the result of IES executing additional contract volumes between the date the acquisition agreement was signed and the closing of the transaction resulting in an increase in the fair value of the net assets acquired as of the acquisition date. The after-tax gain is included within Gain on consolidation and acquisition of businesses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

IES’s operating revenue and net loss included in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the period from November 1, 2014 to December 31, 2014 were approximately $386 million and $(42) million, respectively. The net loss includes pre-tax unrealized losses on derivative contracts of $108 million and the bargain purchase gain of $28 million. Exelon and Generation incurred approximately $7 million of merger and integration related costs which are included within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Merger with Constellation (Exelon, Generation, ComEd, PECO and BGE)

Description of Constellation Merger 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

300

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

Regulatory Matters from the Constellation Merger

In February 2012, the MDPSC issued an order approving the Exelon and Constellation merger. As part of the MDPSC Order, 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 approximately $1 billion.

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		—			—		114		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	$	329

(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.

The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement that was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. See Note 22—Commitments and Contingencies for further information regarding Generation’s total commitments under the lease agreement.

301

Combined Notes to Consolidated Financial Statements—(Continued)

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

The direct investment estimate also includes $600 million to $650 million for Exelon’s and Generation’s commitment to develop or assist in development of 285—300MWs of new generation in Maryland, expected to be completed over a period of 10 years. The MDPSC order 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 or certain specified provisions are elected, 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. However, during the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that Exelon and Generation now believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitment which is included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. While this $44 million loss contingency represents Generation’s best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructed generating plant.

To date, Generation has placed into service 40MW and has commenced development of 150MW of new generation in Maryland towards the 300MW commitment. In July 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland site with at least 120MW of natural gas-fired generation to satisfy one of the commitments to Maryland with achievement of commercial operation expected in 2015. In December 2013, Generation entered into contracts associated with the construction of the 40MW Fourmile Wind project, which was placed in service in December 2014. In December 2014, Generation entered into contracts associated with the construction of the 30MW Fair Wind project in western Maryland with achievement of commercial operations expected in 2015. The wind projects will satisfy a portion of the 125MW Tier I land-based renewables commitment. See Note 22—Commitments and Contingencies for additional information. Exelon’s and Generation’s consolidated financial statements include $185 million and $24 million of capitalized expenditures within Property, plant and equipment, net as of December 31, 2014 and 2013, respectively, and $3 million and $6 million of development costs within Operating and maintenance expense for the periods ended December 31, 2014 and 2013, respectively, associated with the pursuit of these commitments for new generation in the State of Maryland.

Associated with certain of the regulatory approvals required for the merger, on November 30, 2012, a subsidiary of Generation sold three Maryland generating stations and associated assets, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland, to Raven Power Holdings LLC (Raven Power), a subsidiary of Riverstone Holdings LLC. 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 $272 million in 2012 to reflect the difference between the sales price and the carrying value of the generating stations and associated assets. In the first quarter of 2013, Exelon and Generation recorded a pre-tax gain of $8 million to reflect the final settlement of the sales price with Raven Power.

302

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

Pursuant to the MDPSC merger approval conditions, BGE was restricted from paying any dividend on its common shares through the end of 2014, was required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and was not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process for two years following the closing of the merger. Additionally, BGE is subject to other merger approval conditions to enhance BGE’s ring-fencing measures established by order of the MDPSC.

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.

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 Constellation Merger

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.

The financial statements of BGE do not include fair value adjustments for assets or liabilities subject to ratesetting 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

303

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 and liability 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 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. There were no significant adjustments to the purchase price allocation in the first quarter of 2013 and the purchase price allocation was final as of March 31, 2013.

The final purchase price allocation of the Merger of Exelon with Constellation and Exelon’s contribution of certain subsidiaries of Constellation to Generation 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

Impact of the Constellation Merger

It is impracticable to determine the overall financial statement impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger for the year ended December 31, 2012. 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 $3,165 million, $3,065 million and $2,091 million and net

304

Combined Notes to Consolidated Financial Statements—(Continued)

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

income (loss) $211 million, $210 million and $(31) million during the years ended December 31, 2014, 2013 and 2012, respectively.

During the year ended December 31, 2014, Exelon and Generation both incurred merger and integration-related costs of $22 million. Of these amounts, nothing was deferred as a regulatory asset as of December 31, 2014.

During the year ended December 31, 2013, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $142 million, $106 million, $16 million, $9 million and $6 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $17 million, $11 million and $6 million, respectively, as a regulatory asset as of December 31, 2013. Additionally, Exelon and BGE established a regulatory asset of $6 million as of December 31, 2013 for previously incurred 2012 merger and integration-related costs.

During the year ended December 31, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $804 million, $340 million, $41 million, $17 million and $182 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $58 million, $36 million and $22 million, respectively, as a regulatory asset as of December 31, 2012.

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 years ended December 31, 2014, 2013, and 2012. See Note 22—Commitments and Contingencies for additional information.

305

Combined Notes to Consolidated Financial Statements—(Continued)

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

Pro-forma Impact of the Constellation 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 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.


	Exelon				Generation
	Year Ended December 31,				Year Ended December 31,
(unaudited)	2012		2011^(a)		2012		2011 ^(a)
Total revenues		26,700		30,712		17,013		19,494
Net income attributable to Exelon		2,092		974		1,205		324
Basic earnings per share		2.56		1.15		n.a.		n.a.
Diluted earnings per share		2.55		1.14		n.a.		n.a.

(a)	The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011.

(b)	The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011.

Asset Divestitures (Exelon and Generation)

Including the Quail Run generating facility that was sold on January 21, 2015, Generation has sold certain generating assets with a total net book value of approximately $1.8 billion prior to consideration of asset impairments (See Note 8—Impairment of Long-Lived Assets for further information), for total pre-tax proceeds of approximately $1.8 billion (after-tax proceeds of approximately $1.4 billion), which resulted in cumulative pre-tax gains on sale of approximately $412 million, which are included in Gain (loss) on sales of assets on Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income. The proceeds are expected to be used primarily to finance a portion of the acquisition of PHI.

Station

Net Generation
Capacity

Location

Operating Segment

Percent Owned

Fore River

726 MW

North Weymouth, MA

New England

100

West Valley

185 MW

Salt Lake City, UT

Other

100

Keystone

714 MW

Shelocta, PA

Mid-Atlantic

41.98

Conemaugh

532 MW

New Florence, PA

Mid-Atlantic

31.28

Safe Harbor

278 MW

Conestoga, PA

Mid-Atlantic

66.7

Quail Run

488 MW

Odessa, TX

ERCOT

100

306

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2014, the assets and liabilities of the Quail Run generating facility were reported as Assets held for sale and within Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. The table below presents the major classes of assets and liabilities held for sale at December 31, 2014.


	December 31, 2014
Assets:
Property, plant and equipment, net ^(a)	$	143
Inventory		4

Total assets held for sale	$	147

Liabilities:
Accrued expenses	$	1
Asset retirement obligations		4

Total liabilities held for sale^(b)	$	5

(a)

The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income. See Note 8—Impairment of Long-Lived Assets for further information.

(b)	Included within Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation has historically had various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements, see Note 25—Related Party Transactions.

On April 1, 2014, Generation and subsidiaries of Generation, EDF, EDF, Inc. (EDFI) (a subsidiary of EDF) and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI’s rights as a member of CENG (the Integration Transaction). CENG will reimburse Generation for its direct and allocated costs for such services. As part of the arrangement, Nine Mile Point Nuclear Station, LLC, a subsidiary of CENG, also assigned to Generation its obligations as Operator of Nine Mile Point Unit 2 under an operating agreement with Long Island Power Authority, the Unit 2 co-owner. In addition, on April 1, 2014, the Power Services Agency Agreement (PSAA) was amended and extended until the permanent cessation of power generation by the CENG generation plants.

In addition, on April 1, 2014, Generation made a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified available cash flows of CENG and, in any event, payable upon the settlement of the Put Option Agreement discussed below (if the put option is exercised) or payable upon the maturity date of April 1, 2034, whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG made a $400 million special distribution to EDFI.

Exelon, Generation, and subsidiaries of Generation, EDFI and its parent (E.D.F. International S.A.S.), and CENG also executed a Fourth Amended and Restated Operating Agreement for CENG on April 1, 2014, pursuant to which, among other things, CENG committed to make preferred

307

Combined Notes to Consolidated Financial Statements—(Continued)

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

distributions to Generation (after repayment of the $400 million loan and associated interest) quarterly out of specified available cash flows until Generation has received aggregate distributions of $400 million plus a return of 8.5% per annum from April 1, 2014 (Preferred Distribution Rights).

Generation and EDFI also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDFI has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF’s 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation’s rights to other distributions. The beginning of the exercise period will be accelerated if Exelon’s affiliates cease to own a majority of CENG and exercise a related right to terminate the NOSA. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months.

On April 1, 2014, Generation also executed an Indemnity Agreement pursuant to which Generation indemnified EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity.

In addition, on April 1, 2014, Generation, EDFI, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement (EMA) that provides for the transfer of CENG employees to Exelon or one of its affiliates and Exelon’s assumption of the sponsorship of the employee benefit plans (including certain incentive, health and welfare, and postemployment benefit plans, among others) and their related trusts by Exelon as the plan sponsor as of July 14, 2014. The EMA also generally requires CENG to fund the obligation related to pre-transfer service of employees, including the underfunded balance of the pension and other postretirement welfare benefit plans measured as of July 14, 2014 by making periodic payments to Generation. These payments will be made on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG.

As a condition to obtaining regulatory approval for the NOSA and related transactions from the NRC, Exelon executed a support agreement pursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to CENG (Exelon Support Agreement). The Exelon Support Agreement supersedes a previous support agreement under which Generation had agreed to provide up to $205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specified circumstances to provide up to $165 million in additional financial support for CENG. A previous support agreement executed by an affiliate of EDF remains in effect under which the EDF affiliate may be required to provide up to approximately $145 million of financial support for CENG under specified circumstances. The agreements were executed on April 1, 2014 when the NRC licenses were transferred to Generation. No liability has been recognized by Exelon for the guarantees.

Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. From January 1, 2014, through March 31, 2014, Generation recorded $19 million of equity in losses of unconsolidated affiliates related to its investment in CENG and recorded $17 million of revenues from CENG. For the twelve months ended December 31, 2013, Generation recorded $9 million of equity in losses of unconsolidated affiliates related to its investment

308

Combined Notes to Consolidated Financial Statements—(Continued)

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

in CENG and $56 million of revenues from CENG. The book value of Generation’s investment in CENG prior to the consolidation was $1.9 billion, and the book value of the AOCI related to CENG prior to consolidation was $116 million, net of taxes of $77 million.

As a result of the consolidation of CENG on April 1, 2014, there are several additional transactions included in Exelon’s and Generation’s Consolidated Financial Statements between CENG and EDF that are considered related party transactions to Generation. As further described in Note 25—Related Party Transactions EDF and Generation had a PPA with CENG under which they purchased 15% and 85% (through December 31, 2014), respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs. Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation will purchase 49.99% and 50.01%, respectively, of the nuclear output owned by CENG. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For the year ended December 31, 2014, Generation had sales to EDF of $137 million. See discussion above and Note 2—Variable Interest Entities for additional information regarding other transactions, between CENG and EDF included within Exelon and Generation’s financial statements.

See Note 2—Variable Interest Entities for additional information about the Registrant’s VIEs.

Accounting for the Consolidation of CENG

The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s and Generation’s Consolidated Balance Sheets. As a result of the consolidation, Exelon and Generation recorded a net gain of $261 million within their respective Consolidated Statements of Operations and Comprehensive Income. This gain consists of approximately $136 million related to the step up to fair value basis of our ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing transactions between CENG and Generation. The net gain on the consolidation of CENG of $261 million is net of a $7 million payment to EDF.

The fair value of CENG’s assets and liabilities recorded in consolidation 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.

The valuations necessary to assess the fair values of certain assets and liabilities are considered preliminary as a result of the short time period between the execution of the NOSA and the end of the second quarter of 2014. The estimates of the fair value of assets and liabilities may be modified up to one year from April 1, 2014, as more information is obtained about the fair value of assets and liabilities. The principal items that have been revised include the asset retirement obligation liabilities and related asset retirement costs. These items have been updated with inputs from a third party engineering firm with corresponding adjustments recorded in 2014. See Note 15—Asset Retirement Obligations for discussion of the impacts of adjustments recorded during 2014 related to updated estimates of the CENG asset retirement obligation liabilities. In the period of such revisions, these and any other material changes to the fair value assessments have resulted in adjustments to the amounts recorded upon consolidation. In addition, the asset or liability adjustments impacting depreciation and/or accretion expense recorded after the consolidation date have impacted Generation’s post-consolidation results of operations. No material changes are expected to the fair value of assets and liabilities.

309

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation recorded the assets and liabilities of CENG at fair value as of April 1, 2014. The following assets and liabilities of CENG were recorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above:


Fair Values	Exelon and Generation
Current assets	$	499
Nuclear decommissioning trust fund		1,955
Property, plant and equipment		3,017
Nuclear fuel		482
Other assets		10

Total assets		5,963

Current liabilities		237
Asset retirement obligation		1,760
Pension and other employee benefit obligations		281
Unamortized energy contract liabilities		171
Other liabilities		114

Total liabilities		2,563

Total net assets	$	3,400

Generation also recorded the fair value of the noncontrolling interest on its Consolidated Balance Sheets of approximately $1.5 billion, net of the fair value of $152 million for certain specified additional distribution rights under the Operating Agreement. In addition, the noncontrolling interest was further reduced by the $400 million special cash distribution to EDF.

Due to the Preferred Distribution Rights that Generation has on CENG’s available cash, the earnings attributable to the noncontrolling interest on the Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interest on the Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will consider Generation’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’S net assets. For the year ended December 31, 2014, Generation reduced by $13 million the amount of Net income attributable to noncontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of the consolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incremental operating revenues of $218 million and CENG’s net income, prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $407 million during the year ended December 31, 2014.

Exelon and Generation incurred integration-related costs of $26 million for the year ended December 31, 2014. The costs incurred are classified primarily within Operating and maintenance expense in Exelon’s and Generation’s respective Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014.

See Note 17—Severance for integration-related severance costs incurred by Exelon and Generation during the year ended December 31, 2014.

310

Combined Notes to Consolidated Financial Statements—(Continued)

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

6. Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE)

Accounts receivable at December 31, 2014 and 2013 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:


2014	Exelon			Generation			ComEd			PECO			BGE
Unbilled customer revenues	$	1,381		$	823	^(a)	$	204		$	140		$	214
Allowance for uncollectible accounts^(b)		(311	)		(60	)		(84	)		(100	)^(c)		(67	)^(d)


2013	Exelon			Generation			ComEd			PECO			BGE
Unbilled customer revenues	$	1,151		$	584	^(a)	$	201		$	161		$	205
Allowance for uncollectible accounts^(b)		(272	)		(57	)		(62	)		(107	)^(c)		(46	)^(d)

(a)	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.

(b)	Includes the allowance for uncollectible accounts on customer and other accounts receivable.

(c)	Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2014 and 2013, respectively, related to PECO’s current installment plan receivables described below.

(d)

At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE’s provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE’s Consolidated Statements of Operations and Comprehensive Income.

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 $15 million and $19 million as of December 31, 2014 and 2013, 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, 2014 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, 2013 of $18 million consists of $1 million, $4 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, 2014 and 2013 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.

311

Combined Notes to Consolidated Financial Statements—(Continued)

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

7. 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, 2014 and 2013:


	Average Service Life (years)	2014		2013
Asset Category
Electric—transmission and distribution	5-90	$	30,157	$	28,123
Electric—generation	1-56		22,911		20,420
Gas—transportation and distribution	5-90		3,505		3,296
Common—electric and gas	5-50		1,169		1,101
Nuclear fuel^(a)	1-8		5,947		5,196
Construction work in progress	N/A		2,167		1,890
Other property, plant and equipment^(b)	5-50		973		1,017

Total property, plant and equipment			66,829		61,043
Less: accumulated depreciation^(c)			14,742		13,713

Property, plant and equipment, net		$	52,087	$	47,330

(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities at Generation.

(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,673 million and $2,371 million as of December 31, 2014 and 2013, 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	2014			2013			2012
Electric—transmission and distribution		2.93	%		2.91	%		2.76	%
Electric—generation		3.50	%		3.35	%		3.15	%
Gas		2.13	%		2.06	%		2.03	%
Common—electric and gas		7.32	%		7.53	%		7.61	%

312

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, 2014 and 2013:


	Average Service Life (years)	2014		2013
Asset Category
Electric—generation	1-56	$	22,911	$	20,420
Nuclear fuel^(a)	1-8		5,947		5,196
Construction work in progress	N/A		1,404		1,129
Other property, plant and equipment^(b)	6-31		295		400

Total property, plant and equipment			30,557		27,145
Less: accumulated depreciation^(c)			7,612		7,034

Property, plant and equipment, net		$	22,945	$	20,111

(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively.

(b)

Includes buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities.

(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively.

The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.5%, 3.35% and 3.15% for the years ended December 31, 2014, 2013 and 2012, 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, 2014 and 2013:


	Average Service Life (years)	2014		2013
Asset Category
Electric—transmission and distribution	5-80	$	18,884	$	17,334
Construction work in progress	N/A		276		456
Other property, plant and equipment^(a)	39-50		65		60

Total property, plant and equipment			19,225		17,850
Less: accumulated depreciation			3,432		3,184

Property, plant and equipment, net		$	15,793	$	14,666

(a)	Includes buildings under capital lease with a net carrying value at both of December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively.

313

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 3.05%, 2.97% and 2.79% for the years ended December 31, 2014, 2013 and 2012, respectively.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:


	Average Service Life (years)	2014		2013
Asset Category
Electric—transmission and distribution	5-65	$	6,886	$	6,669
Gas—transportation and distribution	5-70		2,039		1,932
Common—electric and gas	5-50		618		600
Construction work in progress	N/A		154		101
Other property, plant and equipment^(a)	50		21		17

Total property, plant and equipment			9,718		9,319
Less: accumulated depreciation			2,917		2,935

Property, plant and equipment, net		$	6,801	$	6,384

(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	2014			2013			2012
Electric—transmission and distribution		2.55	%		2.73	%		2.51	%
Gas		1.84	%		1.79	%		1.77	%
Common—electric and gas		5.16	%		6.65	%		7.54	%

BGE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:


	Average Service Life (years)	2014		2013
Asset Category
Electric—transmission and distribution	5-90	$	6,339	$	6,100
Gas—distribution	5-90		1,761		1,660
Common—electric and gas	5-40		623		578
Construction work in progress	N/A		317		196
Other property, plant and equipment^(a)	20		32		32

Total property, plant and equipment			9,072		8,566
Less: accumulated depreciation			2,868		2,702

Property, plant and equipment, net		$	6,204	$	5,864

(a)	Represents land held for future use and non utility property.

314

Combined Notes to Consolidated Financial Statements—(Continued)

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


Average Service Life Percentage by Asset Category	2014			2013			2012
Electric—transmission and distribution		2.96	%		2.91	%		2.92	%
Gas		2.47	%		2.36	%		2.33	%
Common—electric and gas		9.49	%		8.45	%		7.68	%

See Note 1—Significant Accounting Policies for further information regarding property, plant and equipment policies and accounting for capitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 13—Debt and Credit Agreements for further information regarding Exelon’s, ComEd’s, and PECO’s property, plant and equipment subject to mortgage liens.

8. Impairment of Long-Lived Assets (Exelon and Generation)

Long-Lived Assets (Exelon and Generation)

Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In 2014, updates to the long-term fundamental energy prices, which included a thorough evaluation of key assumptions including gas prices, load growth, plant retirements and renewable growth, suggested that the carrying value of certain wind assets with market price exposure may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014. As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65 million and a pre-tax impairment charge of $86 million was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

In 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects with market price exposure for either all or a portion of the life of the asset may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of eleven wind projects, primarily located in West Texas and Minnesota, were less than their respective carrying values at September 30, 2013. As a result, long-lived assets held and used with a carrying amount of approximately $75 million were written down to their fair value of $32 million and a pre-tax impairment charge of $43 million, net of the impairment amount attributable to noncontrolling interests for certain of the projects, was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

In 2014, certain non-nuclear generating assets were identified as assets held for sale on Exelon’s and Generation’s Consolidated Balance Sheets. When long-lived assets are held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value less costs to sell. Long-lived assets with a carrying amount of approximately $1 billion were written down to their fair value of $556 million and a pre-tax impairment charge of $450 million was recorded in Operating and maintenance expense on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

In 2012, a subsidiary of Generation sold three Maryland generating stations in connection with the Constellation merger. As a result of the transaction, Exelon and Generation recorded a pre-tax impairment charge of $272 million to reflect the difference between the sales price and the carrying value of the generating stations, which was included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 4—Mergers, Acquisitions, and Dispositions for further information on asset sales.

315

Combined Notes to Consolidated Financial Statements—(Continued)

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

In the fourth quarter of 2014, a significant decline in oil prices suggested that the carrying value of certain Upstream assets may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of various Upstream properties, primarily located in Oklahoma and Texas, were less than their respective carrying values at December 31, 2014. As a result, long-lived assets with a combined net book value of approximately $163 million were written down to their fair value of $39 million and a pre-tax impairment charge of $124 million was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. After reflecting the impairment, Generation has $189 million of Upstream assets remaining on its Consolidated Balance Sheets at December 31, 2014. Further declines in commodity prices could potentially result in future impairments of the Upstream assets.

The fair value analysis used in the above impairments was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material.

Nuclear Uprate Program (Exelon and Generation)

Generation is engaged in individual projects as part of a planned power uprate program across its nuclear fleet. When economically viable, 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. Based on ongoing reviews, the nuclear uprate implementation plan was adjusted during 2013 to cancel certain projects. The Measurement Uncertainty Recapture (MUR) uprate projects at the Dresden and Quad Cities nuclear stations were cancelled as a result of the cost of additional plant modifications identified during final design work which, when combined with then current market conditions, made the projects not economically viable. Additionally, the market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. During 2013, Generation recorded a pre-tax charge to Operating and maintenance expense and Interest expense of approximately $111 million and $8 million, respectively, to accrue remaining costs and reverse the previously capitalized costs.

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 coal-fired generating station leases located in Georgia and Texas with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. See Note 14—Income Taxes for further information. 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 operate the stations and keep or market the power itself or require the lessees to arrange for a third-party to bid on a service contract for a period following the lease term. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon’s

316

Combined Notes to Consolidated Financial Statements—(Continued)

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

exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. In 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.

On February 26, 2014, UII and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate the leases on the generating station located in Texas, as described above, prior to its expiration dates. As a result of the lease termination, UII received a net early termination amount of $335 million from CPS and wrote down the net investment in the CPS long-term lease of $336 million in Investments in Exelon’s Consolidated Balance Sheets in 2014; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income in 2014.

Pursuant to the applicable accounting guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, which takes into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements.

Based on the annual reviews performed in 2014 and 2013, the estimated residual value of Exelon’s direct financing leases for the Georgia generating stations experienced other than temporary declines given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $24 million and $14 million pre-tax impairment charge in 2014 and 2013, respectively, for these stations. These impairment charges were recorded in Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheets and the Consolidated Statements of Operations and Comprehensive Income, respectively. Changes in the assumptions described above could potentially result in future impairments of Exelon’s direct financing lease investments, which could be material. Through December 31, 2014, no events have occurred that would require Exelon to review the estimated residual values of its direct financing lease investments subsequent to the review performed in the second quarter of 2014.

At December 31, 2014 and 2013, the components of the net investment in long-term leases were as follows:


	December 31, 2014		December 31, 2013
Estimated residual value of leased assets	$	685	$	1,465
Less: unearned income		324		767

Net investment in long-term leases	$	361	$	698

317

Combined Notes to Consolidated Financial Statements—(Continued)

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

9. 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, 2014 and 2013 were as follows:


	Nuclear generation												Fossil fuel generation							Transmission					Other
	Quad Cities			Peach Bottom			Salem ^(a)			Nine Mile Point Unit 2 ^(g)			Keystone ^(f)		Conemaugh ^(f)		Wyman			PA ^(b)		DE/NJ ^(c)			Other ^(d)
Operator		Generation			Generation			PSEG Nuclear			Generation			GenOn		GenOn		FP&L			First Energy		PSEG
Ownership interest		75.00	%		50.00	%		42.59	%		82.00	%		—		—		5.89	%		Various		42.55	%		44.24	%
Exelon’s share at December 31, 2014:
Plant ^(e)	$	995		$	1,095		$	531		$	676		$	—	$	—	$	3		$	14	$	64		$	2
Accumulated depreciation ^(e)		266			343			150			14			—		—		3			7		34			1
Construction work in progress		15			133			29			48			—		—		—			—		—			—
Exelon’s share at December 31, 2013:
Plant ^(e)	$	941		$	883		$	501		$	—		$	725	$	399	$	3		$	14	$	64		$	2
Accumulated depreciation ^(e)		226			326			134			—			268		220		3			7		34			1
Construction work in progress		27			174			24			—			6		121		—			—		—			—

(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, 2014 and 2013.

(b)

PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.

(c)

PECO owns a 42.55% share in 131 miles of 500kV 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.

(d)	Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey.

(e)	Excludes asset retirement costs.

(f)	As of December 31, 2014, Generation sold its ownership interest in Keystone and Conemaugh. At December 31, 2013, Generation held 41.98% and 31.28% ownership interest in Keystone and Conemaugh, respectively. See Note 4—Mergers, Acquisitions, and Dispositions for additional information.

(g)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet, and as of that date, CENG’s operations are consolidated into Generation’s financial statements. As of December 31, 2013, Generation’s ownership interest in CENG, including Nine Mile Point, was treated as an equity method investment, and thus did not represent an undivided Interest. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information.

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 plants are included in Purchased power and fuel and Operating and maintenance expenses on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses on PECO’s and BGE’s Consolidated Statements of Operations and Comprehensive Income.

318

Combined Notes to Consolidated Financial Statements—(Continued)

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

10. 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, 2014 and 2013 were as follows:


	ComEd						Generation				Exelon
	Gross Amount^(a)		Accumulated Impairment Losses		Carrying Amount		Gross Amount		Carrying Amount		Gross Amount		Accumulated Impairment Losses		Carrying Amount
Balance, January 1, 2013	$	4,608	$	1,983	$	2,625	$	—	$	—	$	4,608	$	1,983	$	2,625
Goodwill from business combination		—		—		—		47		47		47		—		47

Balance, December 31, 2014	$	4,608	$	1,983	$	2,625	$	47	$	47	$	4,655	$	1,983	$	2,672

(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 occur 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 for goodwill, a reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment for its combined business. There is no level below this operating segment for which operating results are regularly reviewed by segment management. Therefore, ComEd’s operating segment is considered its only reporting unit.

Entities assessing goodwill for impairment have the option of first 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 quantitative 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. Any goodwill impairment charge at ComEd will affect Exelon’s consolidated results of operations.

ComEd’s valuation approach is based on a market participant view, pursuant to authoritative guidance for fair value measurement, and utilizes a weighted combination of a discounted cash flow

319

Combined Notes to Consolidated Financial Statements—(Continued)

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

analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case” or “best estimate” projected cash flows for ComEd’s business and includes an estimate of ComEd’s terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include 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.

2014 Goodwill Impairment Assessment. Pursuant to authoritative guidance, ComEd is required to test its goodwill for impairment annually and more frequently if an event occurs or circumstances change that suggest an impairment is more likely than not. ComEd performed a qualitative assessment as of November 1, 2014, for its 2014 annual goodwill impairment assessment and 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 as well as changes in certain market conditions, including the discount rate and EBITDA multiples, while also considering the passing margin from its last quantitative assessment performed as of November 1, 2013.

Prior Goodwill Impairment Assessments. Management concluded the remeasurement of the like-kind exchange position and the charge to ComEd’s earnings in the first quarter of 2013 triggered an interim goodwill impairment assessment and, as a result, ComEd tested its goodwill for impairment as of January 31, 2013. 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.

ComEd performed a quantitative assessment as of November 1, 2013, for its 2013 annual goodwill impairment assessment. The first step of the annual 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.

In both the interim and annual assessments, the discounted cash flow analysis reflected Exelon’s indemnity to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts related to the like-kind exchange position on ComEd’s equity. While neither the interim nor the annual assessments indicated an impairment of ComEd’s goodwill, certain assumptions used to estimate the fair value of ComEd are highly sensitive to changes. Adverse regulatory actions, such as early termination of EIMA, or changes in significant assumptions, including 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 could potentially result in a future impairment of ComEd’s goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2013, the estimated fair value of ComEd would have needed to decrease by more than 10% for ComEd to fail the first step of the impairment test.

320

Combined Notes to Consolidated Financial Statements—(Continued)

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

Management concluded that the May 2012 ICC final Order in ComEd’s 2011 formula rate proceeding triggered 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. ComEd performed a qualitative assessment as of November 1, 2012, for its 2012 annual goodwill impairment assessment and 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 May 2012 Order) as well as changes in certain other market conditions, such as the discount rate and EBITDA multiples.

Other Intangible Assets

Exelon’s, Generation’s and ComEd’s other intangible assets and liabilities, included in Unamortized energy contract assets and Other long-term assets and liabilities in their Consolidated Balance Sheets, consisted of the following as of December 31, 2014:


	Weighted Average Amortization Years ^(h)		Gross			Accumulated Amortization			Net			Estimated amortization expense
	Weighted Average Amortization Years ^(h)		Gross			Accumulated Amortization			Net			2015			2016			2017			2018			2019
Exelon and Generation
Unamortized Energy Contracts ^(a)
Exelon Wind ^(b)		18.0	$	224		$	(55	)	$	169		$	14		$	14		$	14		$	14		$	14
Antelope Valley^(c)		25.0		190			(12	)		178			8			8			8			8			8
Constellation ^(d)		1.5		1,499			(1,451	)		48			19			(31	)		(21	)		11			8
CENG ^(e)		1.7		(97	)		29			(68	)		(20	)		(11	)		(15	)		(18	)		(15	)
Integrys ^(d)		2.4		6			(5	)		1			(8	)		6			1			1			—
Customer Relationships
Constellation ^(d)		12.4		214			(58	)		156			18			18			18			18			17
Integrys ^(d)		10.0		48			(1	)		47			5			5			5			5			5
Trade Names
Constellation ^(d)		10.0		243			(79	)		164			23			23			23			23			23
ComEd
Chicago settlement—1999 agreement ^(f)		21.8		100			(79	)		21			3			3			4			4			4
Chicago settlement—2003 agreement ^(g)		17.9		62			(40	)		22			4			4			3			3			3

Total intangible assets			$	2,489		$	(1,751	)	$	738		$	66		$	39		$	40		$	69		$	67

(a)

Includes unamortized energy contract assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively.

(b)	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states.

(c)	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 230 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc.

(d)	See Note 4—Mergers, Acquisitions, and Dispositions for further information on these acquisitions.

(e)	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.

(f)

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.

321

Combined Notes to Consolidated Financial Statements—(Continued)

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

(g)

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 deferred credits and other liabilities, and other long-term liabilities on Exelon’s and ComEd’s Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.

(h)	Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement.

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2014, 2013 and 2012:


For the Year Ended December 31,	Exelon ^(a)		Generation ^(a)		ComEd
2014	$	179	$	179	$	7
2013		478		550		7
2012		1,150		1,145		7

(a)

At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income

Acquired Intangible Assets

Accounting guidance for business combinations requires the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting.

Unamortized Energy Contracts. Unamortized energy contract assets and liabilities represent the remaining unamortized fair value of non-derivative energy contracts that Generation has acquired. The valuation of unamortized energy contracts 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 fair value 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 Exelon Wind unamortized energy contracts are amortized on a straight line basis over the period in which the associated contract revenues are recognized as a decrease in Operating revenue within Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income. In the case of Antelope Valley, Constellation, CENG and Integrys, 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 dates through either Purchase power and fuel expense or Operating revenues within Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

322

Combined Notes to Consolidated Financial Statements—(Continued)

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

Customer Relationships. The customer relationship intangible 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 fair value 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 accounting guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the customer relationships is recorded in Depreciation and amortization expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The fair value 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. The Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years. The amortization of the trade name is recorded in Depreciation and amortization expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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). Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. 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, 2014, and 2013, PECO had current AECs of $13 million and $19 million, respectively. PECO had no noncurrent AECs and $5 million as of December 31, 2014, and 2013, respectively. As of December 31, 2014, and 2013, Generation had current RECs of $191 million and $158 million, respectively, and $44 million of noncurrent REC’s as of December 31, 2014. As of December 31, 2014, and 2013, ComEd, had current RECs of $4 million and $3 million, respectively. See Note 3—Regulatory Matters and Note 22—Commitments and Contingencies for additional information on RECs and AECs.

323

Combined Notes to Consolidated Financial Statements—(Continued)

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

11. 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, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2014 and 2013:

Exelon


	December 31, 2014										December 31, 2013
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	463	$	3	$	448	$	12	$	463	$	344	$	344
Long-term debt (including amounts due within one year)		21,164		1,208		20,417		1,311		22,936		19,132		19,751
Long-term debt to financing trusts		648		—		—		648		648		648		631
SNF obligation		1,021		—		833		—		833		1,021		790

Generation


	December 31, 2014										December 31, 2013
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	36	$	—	$	24	$	12	$	36	$	22	$	22
Long-term debt (including amounts due within one year)		8,266		—		7,511		1,311		8,822		7,729		7,648
SNF obligation		1,021		—		833		—		833		1,021		790

ComEd


	December 31, 2014										December 31, 2013
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	304	$	—	$	304	$	—	$	304	$	184	$	184
Long-term debt (including amounts due within one year)		5,958		—		6,788		—		6,788		5,675		6,255
Long-term debt to financing trust		206		—		—		213		213		206		202

PECO


	December 31, 2014										December 31, 2013
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,246	$	—	$	2,537	$	—	$	2,537	$	2,197	$	2,358
Long-term debt to financing trusts		184		—		—		199		199		184		180

324

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE


	December 31, 2014										December 31, 2013
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	123	$	3	$	120	$	—	$	123	$	138	$	138
Long-term debt (including amounts due within one year)		1,942		—		2,178		—		2,178		2,011		2,148
Long-term debt to financing trusts		258		—		—		236		236		258		249

Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1), short-term borrowings (Level 2) and third party financing (Level 3). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.

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. The fair value of Exelon’s equity units (Level 1) are valued based on publicly traded securities issued by Exelon.

The fair value of Generation’s non-government-backed fixed rate project financing debt, including nuclear fuel procurement contracts, (Level 3) is based on market and quoted prices for its own and other project financing debt with similar risk profiles. Given the low trading volume in the project financing debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) 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, the 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 (Level 2).

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.

325

Combined Notes to Consolidated Financial Statements—(Continued)

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

Long-Term Debt to Financing Trusts. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

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.

•

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.

•

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.

Transfers in and out of levels are recognized as of the end of the reporting period when 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 were not material. 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. There were no transfers between Level 1 and Level 2 during the year ended December 31, 2014 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.

326

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation and Exelon

The following tables present assets and liabilities measured and recorded at fair value on Exelon’s and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013:


	Generation								Exelon
As of December 31, 2014	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	405	$	—	$	—	$	405	$	1,119	$	—	$	—	$	1,119
Nuclear decommissioning trust fund investments
Cash equivalents		208		37		—		245		208		37		—		245
Equity
Domestic		2,423		2,207		—		4,630		2,423		2,207		—		4,630
Foreign		612		—		—		612		612		—		—		612

Equity funds subtotal		3,035		2,207		—		5,242		3,035		2,207		—		5,242
Fixed income
Corporate debt securities		—		2,023		239		2,262		—		2,023		239		2,262
U.S. Treasury and agencies		996		—		—		996		996		—		—		996
Foreign governments		—		95		—		95		—		95		—		95
State and municipal debt		—		438		—		438		—		438		—		438
Other		—		511		—		511		—		511		—		511

Fixed income subtotal		996		3,067		239		4,302		996		3,067		239		4,302

Middle market lending		—		—		366		366		—		—		366		366
Private equity		—		—		83		83		—		—		83		83
Real estate		—		—		3		3		—		—		3		3
Other		—		301		—		301		—		301		—		301

Nuclear decommissioning trust funds subtotal^(b)		4,239		5,612		691		10,542		4,239		5,612		691		10,542

Pledged assets for Zion Station decommissioning
Cash equivalents		—		15		—		15		—		15		—		15
Equities		6		1		—		7		6		1		—		7
Fixed income
U.S. Treasury and agencies		5		3		—		8		5		3		—		8
Corporate debt		—		89		—		89		—		89		—		89
State and municipal debt		—		10		—		10		—		10		—		10
Other		—		3		—		3		—		3		—		3

Fixed income subtotal		5		105		—		110		5		105		—		110

Middle market lending		—		—		184		184		—		—		184		184

Pledged assets for Zion Station decommissioning subtotal^(c)		11		121		184		316		11		121		184		316

Rabbi trust investments^(d)
Cash equivalents		—		—		—		—		1		—		—		1
Mutual funds^(e)		16		—		—		16		46		—		—		46

Rabbi trust investments subtotal		16		—		—		16		47		—		—		47

327

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Generation												Exelon
As of December 31, 2014	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Commodity derivative assets
Economic hedges		1,667			3,465			1,681			6,813			1,667			3,465			1,681			6,813
Proprietary trading		201			284			27			512			201			284			27			512
Effect of netting and allocation of collateral^(f)		(1,982	)		(2,757	)		(557	)		(5,296	)		(1,982	)		(2,757	)		(557	)		(5,296	)

Commodity derivative assets subtotal		(114	)		992			1,151			2,029			(114	)		992			1,151			2,029

Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments		—			8			—			8			—			31			—			31
Economic hedges		—			12			—			12			—			13			—			13
Proprietary trading		18			9			—			27			18			9			—			27
Effect of netting and allocation of collateral		(17	)		(12	)		—			(29	)		(17	)		(31	)		—			(48	)

Interest rate and foreign currency derivative assets subtotal		1			17			—			18			1			22			—			23
Other investments		—			—			3			3			2			—			3			5

Total assets		4,558			6,742			2,029			13,329			5,305			6,747			2,029			14,081

Liabilities
Commodity derivative liabilities
Economic hedges		(2,241	)		(3,458	)		(788	)		(6,487	)		(2,241	)		(3,458	)		(995	)		(6,694	)
Proprietary trading		(195	)		(295	)		(42	)		(532	)		(195	)		(295	)		(42	)		(532	)
Effect of netting and allocation of collateral^(f)		2,416			3,557			729			6,702			2,416			3,557			729			6,702

Commodity derivative liabilities subtotal		(20	)		(196	)		(101	)		(317	)		(20	)		(196	)		(308	)		(524	)

Interest rate and foreign currency derivative liabilities		—			—			—			—			—			—			—			—
Derivatives designated as hedging instruments		—			(12	)		—			(12	)		—			(41	)		—			(41	)
Economic hedges		—			(2	)		—			(2	)		—			(103	)		—			(103	)
Proprietary trading		(14	)		(9	)		—			(23	)		(14	)		(9	)		—			(23	)
Effect of netting and allocation of collateral		25			10			—			35			25			29			—			54

Interest rate and foreign currency derivative liabilities subtotal		11			(13	)		—			(2	)		11			(124	)		—			(113	)
Deferred compensation obligation		—			(31	)		—			(31	)		—			(107	)		—			(107	)

Total liabilities		(9	)		(240	)		(101	)		(350	)		(9	)		(427	)		(308	)		(744	)

Total net assets	$	4,549		$	6,502		$	1,928		$	12,979		$	5,296		$	6,320		$	1,721		$	13,337

328

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Generation												Exelon
As of December 31, 2013	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets
Cash equivalents^(a)	$	1,006		$	—		$	—		$	1,006		$	1,230		$	—		$	—		$	1,230
Nuclear decommissioning trust fund investments
Cash equivalents		459			—			—			459			459			—			—			459
Equities
Domestic		1,642			2,271			—			3,913			1,642			2,271			—			3,913
Foreign		249			—			—			249			249			—			—			249

Equity funds subtotal		1,891			2,271			—			4,162			1,891			2,271			—			4,162

Fixed income
Corporate debt securities		—			1,753			31			1,784			—			1,753			31			1,784
U.S. Treasury and agencies		882			—			—			882			882			—			—			882
Foreign governments		—			87			—			87			—			87			—			87
State and municipal debt		—			294			—			294			—			294			—			294
Other		—			75			—			75			—			75			—			75

Fixed income subtotal		882			2,209			31			3,122			882			2,209			31			3,122

Middle market lending		—			—			314			314			—			—			314			314
Private equity		—			—			5			5			—			—			5			5
Other		—			14			—			14			—			14			—			14

Nuclear decommissioning trust funds subtotal^(b)		3,232			4,494			350			8,076			3,232			4,494			350			8,076

Pledged assets for Zion Station decommissioning
Cash equivalents		—			26			—			26			—			26			—			26
Equities		16			—			—			16			16			—			—			16
Fixed income
U.S. Treasury and agencies		45			4			—			49			45			4			—			49
Corporate debt		—			227			—			227			—			227			—			227
State and municipal debt		—			20			—			20			—			20			—			20

Fixed income subtotal		45			251			—			296			45			251			—			296

Middle market lending		—			—			112			112			—			—			112			112
Other		—			1			—			1			—			1			—			1

Pledged assets for Zion Station decommissioning subtotal^(c)		61			278			112			451			61			278			112			451

Rabbi trust investments^(d)
Cash equivalents		—			—			—			—			2			—			—			2
Mutual funds^(e)		13			—			—			13			54			—			—			54

Rabbi trust investments subtotal		13			—			—			13			56			—			—			56

Commodity derivative assets											—												—
Economic hedges		493			2,582			885			3,960			493			2,582			885			3,960
Proprietary trading		324			1,315			122			1,761			324			1,315			122			1,761
Effect of netting and allocation of collateral^(f)		(863	)		(3,131	)		(430	)		(4,424	)		(863	)		(3,131	)		(430	)		(4,424	)

Commodity derivative assets subtotal		(46	)		766			577			1,297			(46	)		766			577			1,297

329

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Generation												Exelon
As of December 31, 2013	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Interest rate and foreign currency derivative assets		30			32			—			62			30			39			—			69
Effect of netting and allocation of collateral		(30	)		(2	)		—			(32	)		(30	)		(2	)		—			(32	)

Interest rate and foreign currency derivative assets subtotal		—			30			—			30			—			37			—			37

Other investments		—			—			15			15			—			—			15			15

Total assets		4,266			5,568			1,054			10,888			4,533			5,575			1,054			11,162

Liabilities
Commodity derivative liabilities
Economic hedges		(540	)		(1,890	)		(397	)		(2,827	)		(540	)		(1,890	)		(590	)		(3,020	)
Proprietary trading		(328	)		(1,256	)		(119	)		(1,703	)		(328	)		(1,256	)		(119	)		(1,703	)
Effect of netting and allocation of collateral ^(f)		869			3,007			404			4,280			869			3,007			404			4,280

Commodity derivative liabilities subtotal		1			(139	)		(112	)		(250	)		1			(139	)		(305	)		(443	)

Interest rate and foreign currency derivative liabilities		(31	)		(13	)		—			(44	)		(31	)		(17	)		—			(48	)
Effect of netting and allocation of collateral		31			1			—			32			31			1			—			32

Interest rate and foreign currency derivative liabilities subtotal		—			(12	)		—			(12	)		—			(16	)		—			(16	)

Deferred compensation obligation		—			(29	)		—			(29	)		—			(114	)		—			(114	)

Total liabilities		1			(180	)		(112	)		(291	)		1			(269	)		(305	)		(573	)

Total net assets	$	4,267		$	5,388		$	942		$	10,597		$	4,534		$	5,306		$	749		$	10,589

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Excludes net liabilities of $5 million at both December 31, 2014 and 2013. 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 $3 million and $7 million at December 31, 2014 and 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d)

Excludes $35 million and $32 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Exelon Consolidated. Excludes $11 million and $10 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Generation.

(e)

The mutual funds held by the Rabbi trusts at Exelon Consolidated include $45 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2014, and $53 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2013.

(f)

Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2014. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.

330

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value on the Utilities’ Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013:


	ComEd											PECO										BGE
As of December 31, 2014	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	25	$	—		$	—		$	25		$	12	$	—		$	—	$	12		$	103	$	—		$	—	$	103
Rabbi trust investments in Mutual funds^(a)		—		—			—			—			9		—			—		9			5		—			—		5

Total assets		25		—			—			25			21		—			—		21			108		—			—		108

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)		—		(15	)		—		(15	)		—		(5	)		—		(5	)
Mark-to-market derivative liabilities ^(b)		—		—			(207	)		(207	)		—		—			—		—			—		—			—		—

Total liabilities		—		(8	)		(207	)		(215	)		—		(15	)		—		(15	)		—		(5	)		—		(5	)

Total net assets (liabilities)	$	25	$	(8	)	$	(207	)	$	(190	)	$	21	$	(15	)	$	—	$	6		$	108	$	(5	)	$	—	$	103


	ComEd											PECO										BGE
As of December 31, 2013	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	—	$	—		$	—		$	—		$	175	$	—		$	—	$	175		$	31	$	—		$	—	$	31
Rabbi trust investments in Mutual funds^(a)		5		—			—			5			9		—			—		9			6		—			—		6

Total assets		5		—			—			5			184		—			—		184			37		—			—		37

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)		—		(17	)		—		(17	)		—		(6	)		—		(6	)
Mark-to-market derivative liabilities^(b)		—		—			(193	)		(193	)		—		—			—		—			—		—			—		—

Total liabilities		—		(8	)		(193	)		(201	)		—		(17	)		—		(17	)		—		(6	)		—		(6	)

Total net assets (liabilities)	$	5	$	(8	)	$	(193	)	$	(196	)	$	184	$	(17	)	$	—	$	167		$	37	$	(6	)	$	—	$	31

(a)	At PECO, excludes $14 million of the cash surrender value of life insurance investments at both December 31, 2014 and 2013.

(b)	The Level 3 balance includes the current and noncurrent liability of $20 million and $187 million, respectively, at December 31, 2014, and $17 million and $176 million, respectively, at December 31, 2013, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

331

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2014 and 2013:


	Generation															ComEd						Exelon
For The Year Ended December 31, 2014	Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to- Market Derivatives			Other Investments			Total Generation			Other- ComEd ^(b)			Eliminated in Consolidation			Total
Balance as of January 1, 2014	$	350		$	112		$	465		$	15		$	942		$	(193	)	$	—		$	749
Total realized / unrealized gains (losses)
Included in net income		6			—			526	^(a)		—			532			—			—			532
Included in noncurrent payables to affiliates		14			—			—			—			14			—			(14	)		—
Included in payable for Zion Station decommissioning		—			2			—			—			2			—			—			2
Included in regulatory assets/liabilities		—			—			—			—			—			(14	)		14			—
Change in collateral		—			—			198			—			198			—			—			198
Purchases, sales, issuances and settlements
Purchases		400			120			76	^(c)		2			598			—			—			598
Sales		(15	)		(50	)		(7	)		(8	)		(80	)		—			—			(80	)
Settlements		(64	)		—			—			—			(64	)		—			—			(64	)
Transfers into Level 3		—			—			(7	)		—			(7	)		—			—			(7	)
Transfers out of Level 3		—			—			(201	)		(6	)		(207	)		—			—			(207	)

Balance as of December 31, 2014	$	691		$	184		$	1,050		$	3		$	1,928		$	(207	)	$	—		$	1,721

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, 2014	$	4		$	—		$	640		$	—		$	644		$	—		$	—		$	644

332

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Generation															ComEd						Exelon
For The Year Ended December 31, 2013	Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to- Market Derivatives ^(d)			Other Investments			Total Generation			Other- ComEd^(b)(f)			Eliminated in Consolidation			Total
Balance as of January 1, 2013	$	183		$	89		$	660		$	17		$	949		$	(293	)	$	—		$	656
Total realized / unrealized gains (losses)
Included in net income		2			—			(51	)^(a)		—			(49	)		—			7			(42	)
Included in other comprehensive income		—			—			(219	)		2			(217	)		—			219			2
Included in noncurrent payables to affiliates		8			—			—			—			8			—			(8	)		—
Included in payable for Zion Station decommissioning		—			—			—			—			—			—			—			—
Included in regulatory assets/liabilities		—			—			—			—			—			100			(218	)		(118	)
Change in collateral		—			—			7			—			7			—			—			7
Purchases, sales, issuances and settlements
Purchases		203			62			28			4			297			—			—			297
Sales		(28	)		(39	)		(11	)		(8	)		(86	)		—			—			(86	)
Settlements		(18	)		—			—			—			(18	)		—			—			(18	)
Transfers into Level 3		—			—			86	^(e)		1			87			—			—			87
Transfers out of Level 3		—			—			(35	)		(1	)		(36	)		—			—			(36	)

Balance as of December 31, 2013	$	350		$	112		$	465		$	15		$	942		$	(193	)	$	—		$	749

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, 2013	$	1		$	—		$	156		$	—		$	157		$	—		$	—		$	168

(a)	Includes the reclassification of $114 million and $207 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2014 and 2013, respectively.

(b)	Includes $13 million and $133 million of decreases in fair value and $1 million and ($7) million of realized gains (losses) due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the years ended December 31, 2014 and 2013, respectively.

(c)	Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition.

(d)	Includes $11 million of decreases in fair value and realized gains due to settlements of $215 million associated with Generation’s financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

333

Combined Notes to Consolidated Financial Statements—(Continued)

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

(e)	Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations.

(f)	Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation’s financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in 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, 2014 and 2013:


	Generation							Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net^(a)		Operating Revenues		Purchased Power and Fuel			Other, net^(a)
Total gains (losses) included in net income for the year ended December 31, 2014	$	614	$	(88	)	$	6	$	614	$	(88	)	$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2014	$	663	$	(23	)	$	4	$	663	$	(23	)	$	4


	Generation							Exelon
	Operating Revenues			Purchased Power and Fuel		Other, net^(a)		Operating Revenues			Purchased Power and Fuel		Other, net^(a)
Total gains (losses) included in net income for the year ended December 31, 2013	$	(158	)	$	107	$	2	$	(152	)	$	108	$	2
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2013	$	30		$	126	$	1	$	40		$	127	$	1

(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

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 and CENG’s nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities, Fixed Income and Other. Generation’s and CENG’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 or Level 2.

334

Combined Notes to Consolidated Financial Statements—(Continued)

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

With respect to individually held equity securities, which are included in Domestic or Foreign equities, 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. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity, balanced 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, Generation, and CENG invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. 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.

Private equity investments include investments in operating companies that are not publicly traded on a stock exchange. 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.

335

Combined Notes to Consolidated Financial Statements—(Continued)

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

As of December 31, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $290 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.

See Note 15—Asset Retirement Obligations for further discussion on the NDT fund investments.

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 and consist primarily of mutual funds. These 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. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices.

Mark-to-Market Derivatives (Exelon, Generation, and ComEd). 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 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 derivative contracts are 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 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’ derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information 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 12—Derivative Financial Instruments for further discussion on mark-to-market derivatives.

336

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 as Level 2 in the fair value hierarchy.

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.

Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, certain 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.

337

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 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 more 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 instrument’s 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 approximately $2.75 and $0.34 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 7A.—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 12—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 31,2014			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Generation)^(a)(c)	$	893		Discounted Cash Flow	Forward power price	$	15 - $120	^(d)
					Forward gas price Volatility	$	1.52 - $14.02	^(d)
				Option Model	percentage		8% - 257%

Mark-to-market derivatives—Proprietary trading (Generation)^(a)(c)	$	(15	)	Discounted Cash Flow	Forward power price	$	15 - $117	^(d)

Mark-to-market derivatives (ComEd)	$	(207	)	Discounted Cash Flow	Forward heat rate^(b)		8x - 9x
					Marketability reserve		3.5% - 8%
					Renewable factor		86% - 126%

(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

(b)	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.

(c)	The fair values do not include cash collateral held on level three positions of $172 million as of December 31, 2014.

(d)	The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading.

338

Combined Notes to Consolidated Financial Statements—(Continued)

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


Type of trade	Fair Value at December 31, 2013			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Generation) ^(a)(c)	$	488		Discounted Cash Flow	Forward power price	$	8 - $176	^(d)
					Forward gas price Volatility	$	2.98 - $16.63	^(d)
				Option Model	percentage		15% - 142%

Mark-to-market derivatives—Proprietary trading (Generation)^(a)(c)	$	3		Discounted Cash Flow	Forward power price	$	10 - $176	^(d)

Mark-to-market derivatives (ComEd)	$	(193	)	Discounted Cash Flow	Forward heat rate^(b)		8x - 9x
					Marketability reserve		3.5% - 8%
					Renewable factor		84% - 128%

(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

(b)	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.

(c)	The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013

(d)	The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively.

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 price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation 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, certain corporate debt securities, and private equity investments the fair value is determined using a combination of valuation 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 application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance.

Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to

339

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.

12. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)

The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations.

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 fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical and 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, Generation no longer utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivative economic hedges related to 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 22—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. As such, Generation uses a variety of

340

Combined Notes to Consolidated Financial Statements—(Continued)

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

derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas 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 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, 2014, the percentage of expected generation hedged for the major reportable segments was 93%-96%, 61%-64% and 31%-34% for 2015, 2016, and 2017, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation (which reflects the divestiture impact of Quail Run). Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including Generation’s sales to ComEd, PECO and BGE to serve their retail load. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for more detail regarding divestitures.

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. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts for energy and associated RECs were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reductions was approved in March 2014. 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 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. See Note 3—Regulatory Matters for additional information.

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

341

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.

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 NPNS 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 2014 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 2014 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 SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.

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 (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR 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 NPNS scope 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 10,571 GWh, 8,762 GWh and 12,958 GWh for the years ended December 31, 2014, 2013 and 2012, 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.

342

Combined Notes to Consolidated Financial Statements—(Continued)

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

Interest Rate and Foreign Exchange 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, 2014, Exelon and Generation had $1,450 million and $550 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $3,070 million and $770 million of notional amounts of floating-to-fixed hedges outstanding, respectively. 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 fixed-to-floating swaps would result in an approximate $8 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2014. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign exchange hedges as of December 31, 2014:


	Generation															Other												Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading ^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments			Economic Hedges			Collateral and Netting^(b)			Subtotal			Total
Mark-to-market derivative assets (current assets)	$	7		$	7		$	20		$	(22	)	$	12		$	3		$	—		$	—		$	3		$	15
Mark-to-market derivative assets (noncurrent assets)		1			5			7			(7	)		6			20			1			(19	)		2			8

Total mark-to-market derivative assets		8			12			27			(29	)		18			23			1			(19	)		5			23

Mark-to-market derivative liabilities (current liabilities)		(8	)		(2	)		(14	)		25			1			—			—			—			—			1
Mark-to-market derivative liabilities (noncurrent liabilities)		(4	)		—			(9	)		10			(3	)		(29	)		(101	)		19			(111	)		(114	)

Total mark-to-market derivative liabilities		(12	)		(2	)		(23	)		35			(2	)		(29	)		(101	)		19			(111	)		(113	)

Total mark-to-market derivative net assets (liabilities)	$	(4	)	$	10		$	4		$	6		$	16		$	(6	)	$	(100	)	$	—		$	(106	)	$	(90	)

343

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 proprietary trading 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 any associated cash collateral.

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2013:


	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		$	15		$	(19	)	$	(1	)	$	—		$	(1	)
Mark-to-market derivative assets (noncurrent assets)		26			3			15			(13	)		31			7			38

Total mark-to-market derivative assets		26			6			30			(32	)		30			7			37

Mark-to-market derivative liabilities (current liabilities)		(1	)		(1	)		(18	)		19			(1	)		—			(1	)
Mark-to-market derivative liabilities (noncurrent liabilities)		(10	)		(1	)		(13	)		13			(11	)		(4	)		(15	)

Total mark-to-market derivative liabilities		(11	)		(2	)		(31	)		32			(12	)		(4	)		(16	)

Total mark-to-market derivative net assets (liabilities)	$	15		$	4		$	(1	)	$	—		$	18		$	3		$	21

(a)

(b)	Represents the netting of fair value balances with the same counterparty and any associated cash 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:


		Year Ended December 31,
		2014			2013			2012			2014		2013			2012
	Income Statement Location	Gain (Loss) on Swaps									Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	(16	)	$	(15	)	$	(6	)	$	2	$	(6	)	$	—
Exelon	Interest expense	$	3		$	(24	)	$	(9	)	$	15	$	(3	)	$	(1	)

(a)	For the years ended December 31, 2014 and 2013, the loss on Generation swaps included $(17) million and $16 million realized in earnings, respectively, with $4 million and $2 million excluded from hedge effectiveness testing, respectively.

344

Combined Notes to Consolidated Financial Statements—(Continued)

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

During 2014, Exelon entered into $100 million and $75 million of notional amounts of fixed-to-floating fair value hedges related to interest rate swaps, which expire in 2019 and 2020, respectively. At December 31, 2014, Exelon and Generation had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,450 million and $550 million, with a derivative asset of $29 million and $7 million, respectively. At December 31, 2013, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,275 million and $550 million, with a derivative asset of $26 million and $23 million, respectively. During the years ended December 31, 2014 and 2013, the impact on the results of operations, as a result of the ineffectiveness from fair value hedges, was a $18 million gain and $2 million gain, respectively.

Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley project financings, as discussed in Note 13—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 September 30, 2014. The interest rate swap was designated as a cash flow hedge, and as a result, unrealized losses of approximately $21 million have been recorded to Accumulated OCI, net on Exelon’s and Generation’s Consolidated Balance Sheets. During the third quarter of 2014, the interest rate swap was terminated consistent with the agreements. The unrealized loss of $21 million will be amortized into Interest expense on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income over the term of the DOE guaranteed loan.

During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a total notional amount of $26 million as of December 31, 2014 and expire in 2027. After the closing of the Constellation merger, the swaps were re-designated as cash flow hedges. At December 31, 2014, the subsidiary had a $3 million derivative liability related to these swaps.

During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swap has a notional amount of $26 million as of December 31, 2014, and expires in 2030. This swap is designated as a cash flow hedge. At December 31, 2014, the derivative asset related to the swap was immaterial.

During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $213 million as of December 31, 2014 and expire in 2020. The swaps are designated as cash flow hedges. At December 31, 2014, the subsidiary had a $2 million derivative liability related to the swaps.

During the third quarter of 2014, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $505 million as of December 31, 2014 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At December 31, 2014, the subsidiary had a $8 million derivative liability related to the swap.

345

Combined Notes to Consolidated Financial Statements—(Continued)

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

During 2014, Exelon entered into $400 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated refinance of existing debt. The swaps are designated as cash flow hedges. At December 31, 2014, Exelon had a $28 million derivative liability related to the swaps.

During the years ended December 31, 2014 and 2013, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.

Economic Hedges. During 2014, Exelon entered into $1,900 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated future debt issuance related to the proposed PHI acquisition. At December 31, 2014, Exelon had a $100 million derivative liability related to the swaps.

During the fourth quarter, fixed-to-floating interest rate swaps, which were marked-to-market, acquired as part of the Constellation merger, expired for Exelon and Generation. The notional amounts of the swaps was $150 million.

At December 31, 2014, Generation had $126 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $349 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.

Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon Generation, ComEd, PECO and BGE)

Fair value accounting guidance and disclosures about offsetting assets and liabilities 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 legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted unless Generation is downgraded below investment grade (i.e. to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral including initial margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2014 and 2013, $8 million and $10 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. 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.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e. to BB+ or Ba1).

Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

346

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, 2014:


	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal ^(b)			Economic Hedges ^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	4,992		$	456		$	(4,184	)	$	1,264		$	—		$	1,264
Mark-to-market derivative assets (noncurrent assets)		1,821			56			(1,112	)		765			—			765

Total mark-to-market derivative assets		6,813			512			(5,296	)		2,029			—			2,029

Mark-to-market derivative liabilities (current liabilities)		(4,947	)		(468	)		5,200			(215	)		(20	)		(235	)
Mark-to-market derivative liabilities (noncurrent liabilities)		(1,540	)		(64	)		1,502			(102	)		(187	)		(289	)

Total mark-to-market derivative liabilities		(6,487	)		(532	)		6,702			(317	)		(207	)		(524	)

Total mark-to-market derivative net assets (liabilities)	$	326		$	(20	)	$	1,406		$	1,712		$	(207	)	$	1,505

(a)

Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

(b)

Current and noncurrent assets are shown net of collateral of $(416) million and $(171) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(599) million and $(220) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

347

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, 2013:


	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting ^(a)			Subtotal ^(b)			Economic Hedges ^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	2,616		$	1,476		$	(3,364	)	$	728		$	—		$	728
Mark-to-market derivative assets (noncurrent assets)		1,344			285			(1,060	)		569			—			569

Total mark-to-market derivative assets		3,960			1,761			(4,424	)		1,297			—			1,297

Mark-to-market derivative liabilities (current liabilities)		(2,023	)		(1,410	)		3,292			(141	)		(17	)		(158	)
Mark-to-market derivative liabilities (noncurrent liabilities)		(804	)		(293	)		988			(109	)		(176	)		(285	)

Total mark-to-market derivative liabilities		(2,827	)		(1,703	)		4,280			(250	)		(193	)		(443	)

Total mark-to-market derivative net assets (liabilities)	$	1,133		$	58		$	(144	)	$	1,047		$	(193	)	$	854

(a)

(b)

Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Cash Flow Hedges (Exelon, Generation and ComEd). As discussed previously, effective prior to the Constellation merger, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and is 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. Approximately $2 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. See Note 13—Debt and Credit Agreements for information about reclassifications from Accumulated OCI on interest rate swap activity that occurred after December 31, 2014.

348

Combined Notes to Consolidated Financial Statements—(Continued)

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

The tables below provide the activity of Accumulated OCI related to cash flow hedges for the years ended December 31, 2014 and 2013, 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, 2013			$	532	^(a)(d)	$	368
Effective portion of changes in fair value				—			29	^(e)
Reclassifications from accumulated OCI to net income		Operating Revenues		(413	)^(c)(b)		(277	)
Ineffective portion recognized in income		Operating Revenues		—			—

Accumulated OCI derivative gain at December 31, 2013				119	^(d)		120
Effective portion of changes in fair value				—			(31	)^(e)
Reclassifications from accumulated OCI to net income		Operating Revenues		(117	)^(b)		(117	)

Accumulated OCI derivative gain at December 31, 2014			$	2	^(d)	$	(28	)

(a)	Includes $133 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.

(b)	Amount is net of related income tax expense of $78 million and $270 million for the years ended December 31, 2014 and 2013, respectively.

(c)	Includes $133 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 year ended December 31, 2013.

(d)	Excludes $20 million and $5 million, of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2014 and 2013, respectively.

(e)	Includes $15 million and $15 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 years ended December 31, 2014 and 2013, respectively.

During the years ended December 31, 2014, 2013, and 2012, Generation’s former energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from Accumulated OCI to earnings was a $195 million, $683 million and $1,368 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. Changes in cash flow hedge ineffectiveness were losses of $5 million for the year ended December 31, 2012.

The effect of Exelon’s former energy-related cash flow hedge activity impact on pre-tax earnings based on the reclassification adjustment from Accumulated OCI to earnings was a $195 million, $464 million and $747 million pre-tax gain for the years ended December 31, 2014, 2013 and 2012, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were losses of $5 million for the year ended December 31, 2012. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods as all energy-related cash flow hedge positions were de-designated prior to the Constellation merger date.

349

Combined Notes to Consolidated Financial Statements—(Continued)

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

Economic Hedges (Exelon and Generation). These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps (“treasury”) to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed PHI acquisition. For the years ended December 31, 2014, 2013 and 2012, 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, or interest 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 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 Corporate			Exelon
Year Ended December 31, 2014	Operating Revenues			Purchased Power and Fuel			Interest Expense			Total			Operating Revenues ^(a)		Interest Expense			Total
Change in fair value of commodity positions	$	(413	)	$	(194	)	$	—		$	(607	)	$	—	$	—		$	(607	)
Reclassification to realized at settlement of commodity positions		231			(223	)		—			8			—		—			8

Net commodity mark-to-market gains (losses)		(182	)		(417	)		—			(599	)		—		—			(599	)

Change in fair value of treasury positions		10			—			(2	)		8			—		(100	)		(92	)
Reclassification to realized at settlement of treasury positions		(2	)		—			—			(2	)		—		—			(2	)

Net treasury mark-to market gains (losses)		8			—			(2	)		6			—		(100	)		(94	)

Net mark-to market gains (losses)	$	(174	)	$	(417	)	$	(2	)	$	(593	)	$	—	$	(100	)	$	(693	)

350

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Generation											Intercompany Eliminations			Exelon Corporate		Exelon
Year Ended December 31, 2013	Operating Revenues			Purchased Power and Fuel		Interest Expense			Total			Operating Revenues ^(a)			Interest Expense		Total
Change in fair value of commodity positions	$	286		$	180	$	—		$	466		$	(6	)	$	—	$	460
Reclassification to realized at settlement of commodity positions		(64	)		104		—			40			13			—		53

Net commodity mark-to-market gains (losses)		222			284		—			506			7			—		513

Change in fair value of treasury positions		(1	)		—		(4	)		(5	)		—			—		(5	)
Reclassification to realized at settlement of treasury positions		(1	)		—		—			(1	)		—			—		(1	)

Net treasury mark-to market gains (losses)		(2	)		—		(4	)		(6	)		—			—		(6	)

Net mark-to market gains (losses)	$	220		$	284	$	(4	)	$	500		$	7		$	—	$	507


	Generation										Intercompany Eliminations			Exelon Corporate		Exelon
Year Ended December 31, 2012	Operating Revenues			Purchased Power and Fuel		Interest Expense		Total			Operating Revenues ^(a)			Interest Expense		Total
Change in fair value of commodity positions	$	(362	)	$	215	$	—	$	(147	)	$	(94	)	$	—	$	(241	)
Reclassification to realized at settlement of commodity positions		432			238		—		670			101			—		771

Net commodity mark-to-market gains (losses)		70			453		—		523			7			—		530

Change in fair value of treasury positions		—			—		6		6			—			—		6
Reclassification to realized at settlement of treasury positions		(3	)		—		—		(3	)		—			—		(3	)

Net treasury mark-to market gains (losses)		(3	)		—		6		3			—			—		3

Net mark-to market gains (losses)	$	67		$	453	$	6	$	526		$	7		$	—	$	533

(a)	Prior to the Constellation merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation.

Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2014, 2013, and 2012 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 commodity derivative instruments entered into for proprietary trading purposes and interest rate derivative contracts to hedge risk associated with the interest rate component of underlying commodity positions. 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

351

Combined Notes to Consolidated Financial Statements—(Continued)

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

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		2014			2013			2012
Change in fair value of commodity positions		Operating Revenues	$	(1	)	$	(22	)	$	(13	)
Reclassification to realized at settlement of commodity positions		Operating Revenues		(29	)		(15	)		108

Net commodity mark-to-market gains (losses)		Operating Revenues		(30	)		(37	)		95

Change in fair value of treasury positions		Operating Revenues		1			1			1
Reclassification to realized at settlement of treasury positions		Operating Revenues		3			(3	)		—

Net treasury mark-to market gains (losses)		Operating Revenues		4			(2	)		1

Net mark-to market gains (losses)		Operating Revenues	$	(26	)	$	(39	)	$	96

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 process 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, 2014. 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 exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 7A.—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $43 million, $29 million and $40 million, respectively.

352

Combined Notes to Consolidated Financial Statements—(Continued)

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


Rating as of December 31, 2014	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	$	1,629	$	62	$	1,567		1	$	452
Non-investment grade		49		19		30		—		—
No external ratings
Internally rated—investment grade		479		—		479		—		—
Internally rated—non-investment grade		60		4		56		—		—

Total	$	2,217	$	85	$	2,132		1	$	452


Net Credit Exposure by Type of Counterparty	December 31, 2014
Financial institutions	$	295
Investor-owned utilities, marketers, power producers		958
Energy cooperatives and municipalities		862
Other		17

Total	$	2,132

(a)	As of December 31, 2014, credit collateral held from counterparties where Generation had credit exposure included $69 million of cash and $16 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, 2014, ComEd’s net credit exposure to suppliers was immaterial.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters for additional 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. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of December 31, 2014, 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 additional information.

353

Combined Notes to Consolidated Financial Statements—(Continued)

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

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. As of December 31, 2014, PECO had credit exposure of $8 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 additional information.

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 unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of December 31, 2014, BGE had no net credit exposure to 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

354

Combined Notes to Consolidated Financial Statements—(Continued)

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

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:


	For the Years Ended December 31,
Credit-Risk Related Contingent Feature	2014			2013
Gross Fair Value of Derivative Contracts Containing this Feature ^(a)	$	(1,433	)	$	(1,056	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements ^(b)		1,140			846

Net Fair Value of Derivative Contracts Containing This Feature ^(c)	$	(293	)	$	(210	)

(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features 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 had cash collateral posted of $1,497 million and letters of credit posted of $672 million, and cash collateral held of $77 million and letters of credit held of $24 million as of December 31, 2014 for counterparties with derivative positions. Generation had cash collateral posted of $72 million and letters of credit posted of $364 million and cash collateral held of $206 million and letters of credit held of $34 million at December 31, 2013 for counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $2.4 billion and $2.0 billion as of December 31, 2014 and 2013, respectively. 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 Generation’s 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, 2014, Generation’s and Exelon’s swaps were in a liability position, with a fair value of $16 million and $90 million, respectively.

See Note 24—Segment Information for further information regarding the letters of credit supporting the cash collateral.

Generation entered into supply forward contracts 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

355

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 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, 2014, ComEd held approximately $2 million 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, 2014, 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 3—Regulatory Matters for additional information.

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, 2014, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2014, PECO could have been required to post approximately $36 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, 2014, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2014, BGE could have been required to post approximately $79 million of collateral to its counterparties.

356

Combined Notes to Consolidated Financial Statements—(Continued)

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

13. 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, 2014 and 2013:


	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	2014 ^(a)(b)		2013 ^(a)(b⁾		2014		2013		2014			2013
Exelon Corporate	$	500	$	500	$	—	$	—		—	%		0.27	%
Generation		5,600		5,600		—		—		0.32	%		0.32	%
ComEd		1,000		1,000		304		184		0.33	%		0.40	%
PECO		600		600		—		—		n.a.			n.a.
BGE		600		600		120		135		0.29	%		0.31	%

Total	$	8,300	$	8,300	$	424	$	319

(a)

Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size.

(b)

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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.

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.

357

Combined Notes to Consolidated Financial Statements—(Continued)

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

At December 31, 2014, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements:


							Available Capacity at December 31, 2014
Borrower	Aggregate Bank Commitment ^(a)		Facility Draws		Outstanding Letters of Credit^(c)		Actual		To Support Additional Commercial Paper ^(b)
Exelon Corporate	$	500	$	—	$	6	$	494	$	494
Generation		5,800		—		1,181		4,619		4,504
ComEd		1,000		—		2		998		694
PECO		600		—		1		599		599
BGE		600		—		—		600		480

Total	$	8,500	$	—	$	1,190	$	7,310	$	6,771

(a)

(b)	Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program.

(c)	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.

As of December 31, 2014, 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 2014, 2013 and 2012. PECO did not have any short-term borrowings during 2014, 2013 or 2012.

Exelon


	2014			2013			2012
Average borrowings	$	571		$	254		$	199
Maximum borrowings outstanding		1,164			682			505
Average interest rates, computed on a daily basis		0.32	%		0.37	%		0.48	%
Average interest rates, at December 31		0.53	%		0.35	%		n.a.

Generation


	2014			2013			2012
Average borrowings	$	93		$	42		$	4
Maximum borrowings outstanding		552			291			165
Average interest rates, computed on a daily basis		0.32	%		0.32	%		0.45	%
Average interest rates, at December 31		n.a.			n.a.			n.a.

358

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd


	2014			2013			2012
Average borrowings	$	415		$	203		$	110
Maximum borrowings outstanding		597			446			366
Average interest rates, computed on a daily basis		0.33	%		0.40	%		0.50	%
Average interest rates, at December 31		0.50	%		0.37	%		n.a.

BGE


	2014			2013			2012
Average borrowings	$	64		$	35		$	6
Maximum borrowings outstanding		180			135			76
Average interest rates, computed on a daily basis		0.29	%		0.31	%		0.43	%
Average interest rates, computed at December 31		0.61	%		0.31	%		n.a.

Credit Facilities

On March 28, 2014, ComEd extended for an additional year the expiration date of its unsecured revolving credit 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 expires on March 28, 2019. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to extend the facility for ComEd were not material.

On May 30, 2014, each of Exelon Corporate, Generation, PECO and BGE extended the expiration date of its unsecured revolving credit facility with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, into May 2019, with the exception of a cumulative amount of $315 million in commitments, which expire in April 2018. Costs incurred to extend these facilities were not material.

On October 24, 2014, a $100 million bilateral CENG credit facility was amended and extended for an additional year. This facility has been utilized by CENG to fund working capital and capital projects. This facility does not back Generation’s commercial paper program.

On November 24, 2014, Generation entered into a $25 million bilateral credit facility, scheduled to mature in December of 2016. This facility does not currently back Generation’s commercial paper program.

On January 9, 2015, Generation amended and extended its $75 million bilateral credit facility for an additional two years. This facility does not back Generation’s commercial paper program.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s and BGE’s credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular registrant’s credit rating. Exelon Corporate, Generation, ComEd, PECO and BGE have adders of 27.5, 27.5, 7.5, 0.0 and 0.0 basis points for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and 100.0 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings

359

Combined Notes to Consolidated Financial Statements—(Continued)

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

and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratings of the borrower.

An event of default under any of the Registrants’ revolving credit facilities would not constitute an event of default under any of the other Registrants’ revolving 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 revolving credit facility would constitute an event of default under the Exelon Corporation revolving 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, 2014:


	Exelon	Generation	ComEd	PECO	BGE

Credit facility threshold	2.50 to 1	3.00 to 1	2.00 to 1	2.00 to 1	2.00 to 1

At December 31, 2014, the interest coverage ratios at the Registrants were as follows:


	Exelon		Generation		ComEd		PECO		BGE
Interest coverage ratio		9.19		12.35		7.03		8.72		9.28

Credit Agreements

In May 2014, concurrently and in connection with entering into the agreement to acquire PHI, Exelon entered into a credit facility to which the lenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction and provide flexibility for timing of permanent financing. The bridge credit facility was subsequently reduced to $3.2 billion as a result of the June 2014 debt and equity security issuances discussed below, as well as, the net after-tax proceeds from generating asset divestitures during the second half of 2014. During the year ended December 31, 2014, Exelon recorded $31 million to interest expense in connection with the bridge facility to temporarily finance the PHI acquisition. It is not currently expected that Exelon will be required to draw upon this credit facility to finance the proposed PHI acquisition.

Junior Subordinated Notes

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Net proceeds from the issuance were $1.11 billion, net of a $35 million underwriter fee. The net proceeds are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes.

Each equity unit represents an undivided beneficial ownership interest in Exelon’s 2.5% junior subordinated notes due in 2024 and a forward equity purchase contract which settles in 2017. The junior subordinated notes are expected to be remarketed in 2017. In connection with the remarketing, Exelon may modify the maturity date of the notes to a date earlier than June 1, 2024 but not earlier

360

Combined Notes to Consolidated Financial Statements—(Continued)

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

than June 1, 2020, remove redemption provisions of the notes, or change the interest rate on the notes, including changing the interest rate from fixed to floating. Investors that participate in the remarketing receive the remarketing proceeds and may use those funds to either settle the equity forward upon settlement date or invest in the remarketed debt and use other funds for the share purchase. Exelon intends to use the remarketing proceeds to repay debt issued or for other corporate purposes as soon as practical following such settlements. If the remarketing fails, holders of the notes will have the right to put their notes to Exelon for an amount equal to the principal amount of notes held by such holder plus accrued interest. The equity units carry a total annual distribution rate of 6.5%, which is comprised of a quarterly coupon rate of interest of 2.5% and a quarterly contract payment of 4.0% (contract payments).

Each purchase contract obligates the holder to purchase, and Exelon to sell, for $50.00 a number of shares of Exelon’s common stock in accordance with the conversion ratios set forth below:

•

If the market price equals or exceeds $43.7484, then 1.1429 shares.

•

If the market price is less than $43.7484 but greater than $35.00, a number of shares of common stock having a value, based on the market price, equal to $50.00.

•

If the market price is less than or equal to $35.00, then 1.4286 shares.

A holder’s ownership interest in the notes is pledged to Exelon to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the purchase contract must be secured by a U.S. Treasury security.

At the time of issuance, Exelon determined that the forward equity purchase contract had no value and therefore the entire $1.15 billion of junior subordinated notes were allocated to debt and recorded within Long-term debt on Exelon’s Consolidated Balance Sheet. Additionally, at the time of issuance, the present value of the contract payments of $131 million were recorded to Long-term debt, representing the obligation to make contract payments, with an offsetting reduction to Common stock. The obligation for the contract payments will be accreted to interest expense over the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income. The Long-term debt recorded for the contract payments is considered a non-cash financing transaction that was excluded from Exelon’s Consolidated Statements of Cash Flows. Until settlement of the equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method.

361

Combined Notes to Consolidated Financial Statements—(Continued)

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

Long-Term Debt

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2014 and 2013:

Exelon


	Rates			Maturity Date		December 31,
	Rates			Maturity Date		2014			2013
Long-term debt
Rate stabilization bonds		5.72% — 5.82	%		2017	$	195		$	265
First mortgage bonds ^(a)(b)		1.20% — 6.45	%		2015 - 2044		8,079			7,746
Senior unsecured notes		2.00% — 7.60	%		2015 - 2042		7,071			7,571
Unsecured bonds		2.80% — 6.35	%		2016 - 2036		1,750			1,750
Pollution control note		4.10	%		2014		—			20
Nuclear fuel procurement contracts		3.25% — 3.35	%		2018		70			—
Junior subordinated notes		6.50	%		2017		1,150			—
Nonrecourse debt:
Fixed rates		2.33% — 6.00	%		2031 - 2037		1,166			1,077
Variable rates		2.41% — 5.00	%		2019 - 2030		1,101			150
Notes payable and other ^(c)		6.95% — 7.83	%		2015 - 2053		174			181

Total long-term debt							20,756			18,760
Unamortized debt discount and premium, net							(37	)		(19	)
Fair value adjustment							441			384
Fair value hedge carrying value adjustment, net							4			7
Long-term debt due within one year							(1,802	)		(1,509	)

Long-term debt						$	19,362		$	17,623

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			258

Total long-term debt to financing trusts						$	648		$	648

(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 $32 million and $41 million at December 31, 2014 and 2013, respectively. Lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $12 million will be made in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.

(d)	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.

362

Combined Notes to Consolidated Financial Statements—(Continued)

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

Generation


	Rates			Maturity Date		December 31,
	Rates			Maturity Date		2014			2013
Long-term debt
Senior unsecured notes		2.00% — 7.60	%		2015 - 2042	$	5,771		$	6,271
Social Security Administration		2.93	%		2015		—			1
Pollution control notes		4.10	%		2014		—			20
Nuclear fuel procurement contracts		3.25% — 3.35	%		2018		70			—
Nonrecourse debt:
Fixed rates		2.33% — 6.00	%		2031 - 2037		1,166			1,077
Variable rates		2.41% — 5.00	%		2019 - 2030		1,101			150
Notes payable and other ^(a)		7.83	%		2014 - 2020		26			33

Total long-term debt							8,134			7,552
Fair value adjustment							146			166
Unamortized debt discount and premium, net							(14	)		11
Long-term debt due within one year							(614	)		(561	)

Long-term debt						$	7,652		$	7,168

(a)	Includes Generation’s capital lease obligations of $24 million and $33 million at December 31, 2014 and 2013, respectively. Generation will make lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $4 million in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.

On January 13, 2015, Generation issued $750 million in aggregate principal amount of Senior Notes. The Senior Notes carry an annual interest rate of 2.950%, payable semi-annually, commencing July 15, 2015 and due January 15, 2020. The proceeds of the Senior Notes will be used to fund the optional redemption of Exelon’s $550 million, 4.550% Senior Notes due June 15, 2015 and for general corporate purposes. In addition to the issuance, Exelon terminated $400 million of floating-to-fixed interest rate swaps that had been designated as cash flow hedges. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments at this time are probable not to occur. As a result Exelon will reclassify $26 million of deferred losses in AOCI to Other, net in the first quarter of 2015.

363

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd


	Rates			Maturity Date		December 31,
	Rates			Maturity Date		2014			2013
Long-term debt
First mortgage bonds ^(a)(b)		1.95% — 6.45	%		2015 - 2044	$	5,829		$	5,546
Notes payable and other^(c)		6.95% — 7.49	%		2015 - 2053		148			148

Total long-term debt							5,977			5,694
Unamortized debt discount and premium, net							(19	)		(19	)
Long-term debt due within one year							(260	)		(617	)

Long-term debt						$	5,698		$	5,058

Long-term debt to financing trust ^(d)
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)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2014 and 2013, respectively. Lease payments of less than $1 million will be made from 2015 through expiration at 2053.

(d)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.

PECO


	Rates			Maturity Date		December 31,
	Rates			Maturity Date		2014			2013
Long-term debt
First mortgage bonds ^(a)(b)		1.20% — 5.95	%		2016 - 2044	$	2,250		$	2,200

Total long-term debt							2,250			2,200
Unamortized debt discount and premium, net							(4	)		(3	)
Long-term debt due within one year							—			(250	)

Long-term debt						$	2,246		$	1,947

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)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

364

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE


	Rates			Maturity Date		December 31,
	Rates			Maturity Date		2014			2013
Long-term debt
Rate stabilization bonds		5.72% — 5.82	%		2017		195		$	265
Notes		2.80% — 6.35	%		2016 - 2036	$	1,750		$	1,750

Total long-term debt							1,945			2,015
Unamortized debt discount and premium, net							(3	)		(4	)
Long-term debt due within one year							(75	)		(70	)

Long-term debt						$	1,867		$	1,941

Long-term debt to financing trusts ^(a)
Subordinated debentures to BGE Capital Trust II		6.20	%		2043	$	258		$	258

(a)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.

Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2014 through 2019 and thereafter are as follows:


Year	Exelon			Generation		ComEd			PECO			BGE
2015	$	1,739		$	604	$	260		$	—		$	75
2016		1,269			4		665			300			300
2017		2,400			705		425			—			120
2018		1,415			75		840			500			—
2019		982			682		300			—			—
Thereafter		13,599	^(a)		6,064		3,693	^(b)		1,634	^(c)		1,708	^(d)

Total	$	21,404		$	8,134	$	6,183		$	2,434		$	2,203

(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.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.7 billion of generating assets have been pledged as collateral at December 31, 2014.

Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement, fully amortizing by June 30, 2031 related to a solar construction project in Denver, Colorado. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2014, $7 million was outstanding.

CEU Upstream. In July 2011, Generation entered into a five year asset-based lending agreement associated with certain Upstream gas properties that it owns. The borrowing base committed under the facility is $110 million and can increase to a total of $500 million if the assets

365

Combined Notes to Consolidated Financial Statements—(Continued)

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

support a higher borrowing base and Generation is able to obtain additional commitments from lenders. The facility was amended and extended through January 2019. 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. The agreement is scheduled to expire on January 14, 2019, at a fixed rate of 2.41% annually with interest payable quarterly. As of December 31, 2014, $77 million was outstanding under the facility. The facility includes a provision that requires the Generation entities owning the Upstream gas properties subject to the agreement to maintain a current ratio of one-to-one. As of December 31, 2014, Generation was in compliance with this provision.

Sacramento PV Energy. In July 2011, a subsidiary of Generation entered into a 19-year, $41 million nonrecourse note to finance a 30MW solar facility in Sacramento, California. The note bears interest at a variable rate equal to the six-month LIBOR plus 2.25%. Interest is payable quarterly and is secured by the equity interests and assets of the subsidiary. The note is scheduled to mature on December 31, 2030. As of December 31, 2014, $35 million was outstanding. The subsidiary also executed interest rate swaps with an initial notional value of $30 million in order to convert the variable interest payments to fixed payments on 75% of the $41 million facility amount, as required by the debt covenants. See Note 12—Derivative Financial Instruments for additional information regarding interest rate swaps.

Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $10 million solar loan agreement, fully amortizing by December 31, 2031 related to a solar construction project in Holyoke, Massachusetts. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2014, $10 million was outstanding. The agreement includes a provision that requires Generation to establish and maintain a reserve fund to be held by Holyoke Solar Cooperative. As of December 31, 2014, Generation was in compliance with this provision.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in the first half of 2014. The loan will mature on January 5, 2037. Interest rates on the loan are fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. As of December 31, 2014, $557 million was outstanding.

In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2014, Generation had $156 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. Generation expects to contribute approximately $2 million in additional equity contributions.

In connection with this agreement, on September 28, 2011, Generation entered into a floating-to-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, it subsequently entered into a series of fixed-to-floating interest rate swaps to offset portions of the original interest rate hedge. During the third quarter of 2014, the original interest rate swap was terminated, consistent with the agreements. See Note 12—Derivative Financial Instruments for additional information regarding the interest rate swaps associated with Antelope Valley.

366

Combined Notes to Consolidated Financial Statements—(Continued)

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

Constellation Solar Horizons. In September 2012, a subsidiary of Generation entered into an 18-year $38 million nonrecourse note to recover capital used to build a 16MW solar facility in Emmitsburg, Maryland. The note is schedule to mature on September 7, 2030. The note bears interest at a variable rate equal to the three-month LIBOR plus 2.25%. Interest is payable quarterly, and the note is secured by the equity interests and assets of the subsidiary. As of December 31, 2014, $34 million was outstanding. The subsidiary also executed interest rate swaps for an initial notional amount of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $38 million facility amount, as required by the debt covenants. See Note 12—Derivative Financial Instruments for additional information regarding interest rate swaps.

Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million aggregate principal amount of Continental Wind’s 6.00% senior secured notes due February 28, 2033 with interest payable semi-annually. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. As of December 31, 2014, $592 million was outstanding. In connection with this nonrecourse project financing, Exelon terminated existing interest rate swaps with a total notional amount of $350 million during the third quarter of 2013, and realized a total gain of $26 million upon termination. The gain on the interest rate swaps was recorded within OCI and will reduce the effective interest rate over the life of the debt for Exelon. See Note 12—Derivative Financial Instruments for additional information on the interest rate swaps.

In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2014, the Continental Wind letter of credit facility had $47 million in letters of credit outstanding related to the project.

ExGen Renewables I. On February 6, 2014, ExGen Renewables I, LLC (EGR), an indirect subsidiary of Exelon and Generation, borrowed $300 million aggregate principal amount pursuant to a nonrecourse senior secured loan, due February 6, 2021. The proceeds were distributed to Generation for its general business purposes. The loan bears interest at a variable rate equal to LIBOR plus 4.25%, subject to a 1% floor with interest payable quarterly. EGR indirectly owns Continental Wind. As of December 31, 2014, $282 million was outstanding. In addition to the financing, EGR entered into interest rate swaps with an initial notional amount of $240 million at an interest rate of 2.03% to manage a portion of the interest rate exposure in connection with the financing. See Note 12—Derivative Financial Instruments for additional information regarding interest rate swaps.

ExGen Texas Power. In September 2014, ExGen Texas Power, LLC (EGTP), an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan, scheduled to mature on September 18, 2021. The net proceeds were distributed to Generation for general business purposes. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2014, $673 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. In addition to the financing, EGTP entered into interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 12—Derivative Financial Instruments for additional information regarding interest rate swaps.

367

Combined Notes to Consolidated Financial Statements—(Continued)

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

14. 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, 2014	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	121		$	360		$	(171	)	$	28		$	24
Deferred		576			(35	)		395			87			90
Investment tax credit amortization		(20	)		(16	)		(2	)		—			(1	)
State
Current		42			35			7			(2	)		—
Deferred		(53	)		(137	)		39			1			27

Total	$	666		$	207		$	268		$	114		$	140


For the Year Ended December 31, 2013	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	744		$	250		$	160		$	126		$	9
Deferred		140			360			(27	)		23			100
Investment tax credit amortization		(15	)		(11	)		(2	)		(1	)		(1	)
State
Current		181			50			50			16			—
Deferred		(6	)		(34	)		(29	)		(2	)		26

Total	$	1,044		$	615		$	152		$	162		$	134


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

368

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, 2014	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		1.3			(1.9	)		4.5			(0.1	)		5.0
Qualified nuclear decommissioning trust fund income		2.4			4.8			—			—			—
Tax exempt income		(0.2	)		(0.5	)		—			—			—
Domestic production activities deduction		(2.0	)		(4.1	)		—			—			—
Health care reform legislation		0.1			—			0.2			—			0.2
Amortization of investment tax credit, net deferred taxes		(1.1	)		(2.0	)		(0.3	)		(0.1	)		(0.3	)
Plant basis differences		(1.9	)		—			(0.1	)		(10.4	)		0.2
Production tax credits and other credits		(2.4	)		(4.8	)		—			—			—
Non-controlling interest		(1.8	)		(3.7	)		—			—			—
Statute of limitations expiration		(2.6	)		(5.3	)		—			—			—
Other		—			(0.6	)		0.3			0.1			(0.2	)

Effective income tax rate		26.8	%		16.9	%		39.6	%		24.5	%		39.9	%


For the Year Ended December 31, 2013	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		4.8			1.8			3.4			1.6			4.9
Qualified nuclear decommissioning trust fund income		3.7			6.1			—			—			—
Tax exempt income		(0.2	)		(0.3	)		—			—			—
Domestic production activities deduction		—			—			—			—			—
Health care reform legislation		0.1			—			0.7			—			0.2
Amortization of investment tax credit, net deferred taxes		(1.9	)		(3.0	)		(0.6	)		(0.1	)		—
Plant basis differences		(1.6	)		—			(0.8	)		(7.1	)		(0.2	)
Production tax credits and other credits		(2.1	)		(3.4	)		(0.1	)		—			—
Statute of limitations expiration		(0.1	)		(0.2	)		—			—			—
Other		(0.1	)		0.7			0.3			(0.3	)		(0.9	)

Effective income tax rate		37.6	%		36.7	%		37.9	%		29.1	%		39.0	%


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		(3.5	)		4.9			4.6			2.0			24.3
Qualified nuclear decommissioning trust fund income		5.4			9.1			—			—			—
Tax exempt income		(0.2	)		(0.4	)		—			—			—
Domestic production activities deduction		—			—			—			—			—
Health care reform legislation		0.1			—			0.4			—			11.6
Amortization of investment tax credit		(1.1	)		(1.3	)		(0.4	)		(0.3	)		(8.6	)
Plant basis differences		(2.4	)		—			(0.3	)		(11.5	)		(9.0	)
Production tax credits and other credits		(2.2	)		(3.7	)		—			—			—
Fines and Penalties		2.6			4.4			—			—			—
Merger expenses ^(c)		2.4			—			—			—			24.2
Statute of limitations expiration		(0.1	)		(0.3	)		—			—			—
Other		(1.1	)		(0.4	)		(0.6	)		(0.2	)		(13.9	)

Effective income tax rate		34.9	%		47.3	%		38.7	%		25.0	%		63.6	%

369

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.

(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 and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2014 and 2013 are presented below:


For the Year Ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(12,143	)	$	(3,834	)	$	(3,945	)	$	(2,749	)	$	(1,661	)
Accrual based contracts		(178	)		(178	)		—			—			—
Derivatives and other financial instruments		(46	)		(79	)		(4	)		—			—
Deferred pension and postretirement obligation		1,914			(390	)		(543	)		2			(53	)
Nuclear decommissioning activities		(726	)		(726	)		—			—			—
Deferred debt refinancing costs		112			57			(18	)		(2	)		(4	)
Regulatory assets and liabilities		(1,824	)		—			(286	)		27			(258	)
Tax loss carryforward		111			48			—			11			39
Tax credit carryforward		97			143			—			—			—
Investment in CENG		(563	)		(563	)		—			—			—
Other, net		1,029			346			255			111			30

Deferred income tax liabilities (net)	$	(12,217	)	$	(5,176	)	$	(4,541	)	$	(2,600	)	$	(1,907	)
Unamortized investment tax credits		(555	)		(528	)		(20	)		(2	)		(5	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(12,772	)	$	(5,704	)	$	(4,561	)	$	(2,602	)	$	(1,912	)


For the Year Ended December 31, 2013	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(11,612	)	$	(3,879	)	$	(3,523	)	$	(2,573	)	$	(1,538	)
Accrual based contracts		(214	)		(214	)		—			—			—
Derivatives and other financial instruments		(509	)		(505	)		(4	)		—			—
Deferred pension and postretirement obligation		1,489			(362	)		(522	)		—			(74	)
Nuclear decommissioning activities		(647	)		(646	)		—			—			—
Deferred debt refinancing costs		173			79			(21	)		(3	)		(5	)
Regulatory assets and liabilities		(1,611	)		—			(241	)		42			(253	)
Tax loss carryforward		252			76			47			11			52
Tax credit carryforward		534			534			—			—			—
Investment in CENG		(541	)		(541	)		—			—			—
Other, net		804			67			154			122			26

Deferred income tax liabilities (net)	$	(11,882	)	$	(5,391	)	$	(4,110	)	$	(2,401	)	$	(1,792	)
Unamortized investment tax credits		(490	)		(454	)		(22	)		(3	)		(6	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(12,372	)	$	(5,845	)	$	(4,132	)	$	(2,404	)	$	(1,798	)

370

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, 2014.


	Exelon			Generation			ComEd		PECO			BGE
Federal
Federal general business credits carryforward		184	^(a)		184			—		—			—

State
State net operating losses and other credit carryforwards		3,141	^(b)		1,693	^(c)		—		170	^(d)		730	^(e)
Deferred taxes on state tax attributes (net)		169			96			—		11			39
Valuation allowance on state tax attributes		50			48			—		—			1

(a)	Exelon’s federal general business credit carryforwards will expire beginning in 2032.

(b)	Exelon’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015

(c)	Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015.

(d)	PECO’s state net operating losses will expire beginning in 2031.

(e)	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, 2014, 2013 and 2012:


	Exelon			Generation			ComEd			PECO		BGE
Unrecognized tax benefits at January 1, 2014	$	2,175		$	1,415		$	324		$	44	$	—
Increases based on tax positions related to 2014		15			15			—			—		—
Change to positions that only affect timing		(255	)		33			(175	)		—		—
Increases based on tax positions prior to 2014		18			18			—			—		—
Decreases based on tax positions prior to 2014		(1	)		(2	)		—			—		—
Decrease from settlements with taxing authorities		(35	)		(34	)		—			—		—
Decreases from expiration of statute of limitations		(88	)		(88	)		—			—		—

Unrecognized tax benefits at December 31, 2014	$	1,829		$	1,357		$	149		$	44	$	—


	Exelon			Generation			ComEd			PECO		BGE
Unrecognized tax benefits at January 1, 2013	$	1,024		$	876		$	67		$	44	$	—
Increases based on tax positions related to 2013		19			19			—			—		—
Change to positions that only affect timing		649			36			257			—		—
Increases based on tax positions prior to 2013		493			493			—			—		—
Decreases based on tax positions prior to 2013		(6	)		(5	)		—			—		—
Decreases from expiration of statute of limitations		(4	)		(4	)		—			—		—

Unrecognized tax benefits at December 31, 2013	$	2,175		$	1,415		$	324		$	44	$	—

371

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, 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		$	—

Included in Exelon’s unrecognized tax benefits balance at December 31, 2014 and 2013 are approximately $1,129 million and $1,387 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 $701 million and $672 million, respectively, of unrecognized tax benefits at December 31, 2014 that, if recognized, would decrease the effective tax rate. Exelon and Generation had $788 million and $768 million, respectively, of unrecognized tax benefits at December 31, 2013 that, if recognized, would decrease the effective tax rate.

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. Generation filed a complaint in the United States Court of Federal Claims on February 20, 2009 to contest this determination. During the first and second quarters of 2013, AmerGen and the DOJ completed and filed cross motions for summary judgment. On September 17, 2013, the Court granted the government’s motion denying AmerGen’s claims for refund. In the first quarter of 2014, Exelon filed an appeal of the decision to the United States Court of Appeals for the Federal Circuit and oral arguments were heard in January of 2015.

Due to the possibility of final resolution through an appellate decision, Generation continues to believe that it is reasonably possible that the $661 million of total unrecognized tax benefits will significantly decrease in the next twelve months.

372

Combined Notes to Consolidated Financial Statements—(Continued)

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

Settlement of Income Tax Audits and Litigation

As of December 31, 2014, Exelon and Generation have approximately $188 million of state unrecognized tax benefits that could significantly increase or decrease within the 12 months after the reporting date as a result of completing audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate.

See Other Tax Matters—Like Kind Exchange section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months.

Total amounts of interest and penalties recognized

The following table represents the net interest receivable (payable), including interest related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.


Net interest receivable (payable) as of	Exelon			Generation			ComEd			PECO		BGE
December 31, 2014	$	(310	)	$	40		$	(203	)	$	3	$	(1	)
December 31, 2013		(349	)		(37	)		(174	)		3		—

The following table sets forth the net interest expense, including interest related to tax positions, recognized in interest expense (income) in other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. The Registrants have not accrued any material penalties with respect to uncertain tax positions.


Net interest expense (income) for the years ended	Exelon			Generation			ComEd			PECO			BGE
December 31, 2014	$	(36	)	$	(50	)	$	6		$	—		$	1
December 31, 2013		391			17			281			(1	)		—
December 31, 2012		(1	)		11			(20	)		(1	)		9

Description of tax years that remain open to assessment by major jurisdiction


Taxpayer	Open Years
Exelon (and predecessors) and subsidiaries consolidated Federal income tax returns		1999, 2001-2013
Constellation and subsidiaries consolidated Federal income tax returns		2011-March 2012
Exelon and subsidiaries Illinois unitary income tax returns		2007-2013
Constellation combined New York corporate income tax returns		2008-2013
Various separate company Pennsylvania corporate net income tax returns		2010-2013
BGE Maryland corporate net income tax returns		2011-2013
Various Exelon Maryland corporate net income tax returns		2012-2013
Various Constellation (Non-BGE) Maryland corporate net income tax returns		2011-2013

Other Tax Matters

Like-Kind Exchange

Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was

373

Combined Notes to Consolidated Financial Statements—(Continued)

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

deferred by reinvesting a portion of 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 this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999.

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 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 $90 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. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, 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 is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013, Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $170 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the unpaid tax liabilities related to 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. In addition, ComEd will continue to record 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. Exelon continues to believe that it is unlikely that the IRS’s assertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded.

374

Combined Notes to Consolidated Financial Statements—(Continued)

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

On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. The litigation could take three to five years including appeals, if necessary. Decisions in the Tax Court are not controlled by the Federal Circuit’s decision in Consolidated Edison.

In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. The termination resulted in a 2014 tax payment of approximately $285 million by Exelon, including approximately $155 million by ComEd representing the remaining gain deferred pursuant to the like-kind exchange transaction. In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon will be required to pay the full amount of tax and after-tax interest discussed in the preceding paragraph but will ultimately be entitled to a refund of the 2014 tax payment. See Note 8—Impairment of Long-Lived Assets for further details.

Accounting for Generation Repairs (Exelon and Generation)

On April 30, 2013, the IRS issued Revenue Procedure 2013-24 providing guidance for determining the appropriate tax treatment of costs incurred to repair electric generation assets. Generation will change its method of accounting for deducting repairs in accordance with this guidance beginning with its 2014 tax year. Generation has calculated that adoption of the new method will result in a cash tax detriment of approximately $120 million.

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 domestic production activities deduction, which was reflected in the effective income tax rate reconciliation in 2011 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, and $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.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 in the near future. Exelon, PECO and BGE will determine the financial statement impacts of the gas distribution repair costs accounting method changes after guidance is issued.

Accounting for Final Tangible Property Regulations (Exelon, Generation, ComEd, PECO, and BGE)

On September 19, 2013, the Treasury Department and the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce, or improve tangible property. The Registrants have assessed the financial impact of this guidance and do not expect it to have a material impact. Any changes in method of accounting required to conform to the final regulations will be made for the Registrant’s 2014 taxable year.

Long-Term State Tax Apportionment (Exelon and Generation)

As a result of the merger with Constellation, Exelon and Generation re-evaluated their long-term state tax apportionment in the first quarter of 2012. 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.

The long-term state tax apportionment was revised in the fourth quarter of 2014 pursuant to Exelon’s long-term state tax apportionment policy, resulting in the recording of a deferred state tax benefit for Exelon and Generation of $28 million (net of Federal taxes) and $40 million (net of Federal taxes), respectively. The amounts recorded for 2013 in accordance with the policy were immaterial.

Allocation of Tax Benefits (Exelon, Generation, ComEd, PECO and BGE)

Generation, ComEd, PECO and BGE 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

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 2014, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $55 million and $25 million, respectively. ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of tax net operating losses.

During 2013, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $26 million and $27 million, respectively. During 2013, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd’s and BGE’s tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.

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 and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd’s and BGE’s tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.

ComEd received a non-cash contribution to equity from Exelon in 2012 of $11 million, related to tax benefits associated with capital projects constructed by ComEd on behalf of Exelon and Generation.

15. 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 for financial accounting and reporting purposes, 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.

377

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, 2013 to December 31, 2014:


	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2013	$	4,741
Accretion expense		259
Net decrease due to changes in, and timing of, estimated future cash flows		(140	)
Costs incurred to decommission retired plants		(5	)

Nuclear decommissioning ARO at December 31, 2013 ^(a)		4,855
Consolidation of CENG ^(b)		1,760
Accretion expense		334
Net increase due to changes in, and timing of, estimated future cash flows		19
Costs incurred to decommission retired plants		(7	)

Nuclear decommissioning ARO at December 31, 2014 ^(a)	$	6,961

(a)	Includes $8 million and $9 million as the current portion of the ARO at December 31, 2014 and 2013, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

(b)	Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.

During 2014, Generation’s ARO increased by approximately $2.1 billion. The increase is largely driven by the recording of an ARO on Exelon’s and Generation’s Consolidated Balance Sheets at fair value, including subsequent purchase accounting adjustments, upon consolidation of CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC ). The change in the ARO was also driven by an increase for accretion of the obligation and an increase in the estimated costs to decommission Byron, Braidwood, and LaSalle nuclear units resulting from the completion of updated decommissioning costs studies received during 2014 as part of the annual assessment. These increases in the ARO were partially offset by decreases in the ARO due to a reduction in estimated escalation rates, primarily for labor and energy costs. The increase in the ARO due to the changes in, and timing of, estimated cash flows was offset within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets, aside from an approximate $16 million credit to income, which is included in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

During 2013, Generation’s ARO increased by approximately $114 million. The increase is largely driven by an increase in the estimated costs to decommission the Limerick and Three Mile Island nuclear units resulting from the completion of updated decommissioning costs studies received during 2013 and an increase for accretion of the obligation. These increases in the ARO were offset by decreases to the ARO due to changes in long-term escalation rates, primarily for labor and energy costs, as well as changes in the timing of the future nominal cash flows coupled with the fact that cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows was entirely offset by decreases in Property, plant and equipment within Exelon’s and Generation’s Consolidated Balance Sheets.

378

Combined Notes to Consolidated Financial Statements—(Continued)

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

Nuclear Decommissioning Trust Fund Investments

NDT funds have been established for each generating station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, 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 Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. 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 approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. Aside from the former PECO units, Generation does not currently collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from utility customers. Apart from the contributions made to the NDT funds from amounts previously collected from ComEd and currently collected from 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, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, 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, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls, would be borne by Generation. No recourse exists to collect additional amounts for any of Generation’s other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation’s other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG’s acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to nuclear decommissioning trust funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions

379

Combined Notes to Consolidated Financial Statements—(Continued)

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

are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.

At December 31, 2014, and 2013, Exelon and Generation had NDT fund investments totaling $10,537 million and $8,071 million, respectively. At December 31, 2014, approximately 52% of the funds were invested in equity securities and 48% were invested in fixed income securities. At December 31, 2013, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed income securities. 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.

The following table provides unrealized gains on NDT funds for 2014, 2013 and 2012:


	Exelon and Generation
	For the Years Ended December 31,
	2014		2013		2012
Net unrealized gains on decommissioning trust funds—Regulatory Agreement Units^(a)	$	180	$	406	$	386
Net unrealized gains on decommissioning trust funds—Non-Regulatory Agreement Units^(b)(c)		134		146		105

(a)	Net unrealized gains 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 $29 million, $7 million and $73 million of net unrealized gains related to the Zion Station pledged assets in 2014, 2013 and 2012, respectively. Net unrealized gains 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 related to Generation’s NDT funds with Non-Regulatory Agreement Units 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 are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

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 are expected to 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 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 expected value of the NDT fund for

380

Combined Notes to Consolidated Financial Statements—(Continued)

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

any former ComEd unit fall below the amount of the expected 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. As of December 31, 2014, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, 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 former PECO units, regardless of whether the funds held in the NDT funds are expected to 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 Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Refer to Note 3—Regulatory Matters and Note 25—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.

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 assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF and decommission the SNF dry storage facility, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to its decommissioning efforts at Zion Station. During 2013, EnergySolutions entered a definitive acquisition agreement and was acquired by another Company. Generation 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.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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’s 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 for Zion Station decommissioning in Generation’s 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. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $86 million, which is included within the nuclear decommissioning ARO at December 31, 2014. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2014 and 2013:


	Exelon and Generation
	2014		2013
Carrying value of Zion Station pledged assets	$	319	$	458
Payable to Zion Solutions^(a)		292		414
Current portion of payable to Zion Solutions^(b)		137		109
Cumulative withdrawals by Zion Solutions to pay decommissioning costs		666		498

(a)	Excludes a liability recorded within Exelon’s and 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 Exelon’s and Generation’s Consolidated Balance Sheets.

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 constructed a dry cask storage facility on the land and has loaded the SNF from the SNF pools onto the dry cask storage facility 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 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 and its parent company have also provided a performance guarantee and EnergySolutions has 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.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

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 type 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, 2014 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, 2014 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 6% to 6.3% (as compared to a historical 5-year annual average pre-tax return of approximately 9%).

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.

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Combined Notes to Consolidated Financial Statements—(Continued)

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

On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation had in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff’s review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. On March 26, 2014, in accordance with a NRC requirement with respect to units involved in a merger or acquisition, CENG submitted its NRC-required decommissioning funding status report as of December 31, 2013 and no additional financial assurance was required.

On March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for reactors that have been shut down except for Zion Station which is included on a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation. During 2014, the operating license for Limerick Unit 1 was extended by 20 years. As a result of this extension, and the subsequent funding assurance calculation performed by the NRC, it was found that the parent company guarantee was no longer required and thus the parent guarantee for Limerick Unit 1 will be cancelled effective March 13, 2015. See Note 3—Regulatory Matters for additional information regarding the operating license extension for Limerick Unit 1.

Generation will file its next biennial decommissioning funding status report with the NRC on or before March 31, 2015. That report will reflect the status of decommissioning funding assurance as of December 31, 2014. Due to increased cost estimates received in the second half of 2014, Braidwood Unit 1, Braidwood Unit 2, and Byron Unit 2 do not have adequate funding assurance based on the most recent calculations as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on these funds on or before March 31, 2017.

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 Funding 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 January 31, 2013 letter from the NRC does not take issue with Generation’s current funding status, and as reflected in Generation’s April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. On May 1, 2014, the NRC issued its final determination. Although the NRC determined that these historical status reports did not provide complete and accurate information, the

384

Combined Notes to Consolidated Financial Statements—(Continued)

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

violation of the regulatory requirements was not a deliberate violation. The NRC noted the low safety significance and Generation’s corrective actions to satisfy the NRC Staff’s expectations and issued a Severity Level IV violation, with no monetary penalty. A Severity Level IV violation is the lowest level of violation.

In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation’s reporting and funding of the future decommissioning of Generation’s nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon.

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 units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

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.

385

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 non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2013 to December 31, 2014:


	Exelon			Generation			ComEd			PECO			BGE
Non-nuclear AROs at January 1, 2013	$	343		$	207		$	99		$	29		$	8
Net increase (decrease) due to changes in, and timing of, estimated future cash flows^(a)		1			(11	)		—			—			12
Development projects ^(b)		2			2			—			—			—
Accretion expense^(c)		18			13			4			1			—
Payments		(13	)		(10	)		(2	)		—			(1	)

Non-nuclear AROs at December 31, 2013 ^(d)		351			201			101			30			19
Net increase (decrease) due to changes in, and timing of, estimated future cash flows^(a)		(1	)		(2	)		2			—			(1	)
Development projects ^(b)		11			11			—			—			—
Accretion expense^(c)		15			11			3			1			—
Liabilities held for sale ^(e)		(4	)		(4	)		—			—			—
Sale of generating assets ^(f)		(20	)		(20	)		—			—			—
Payments		(6	)		(3	)		(2	)		(1	)		—

Non-nuclear AROs at December 31, 2014 ^(d)	$	346		$	194		$	104		$	30		$	18

(a)

During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014. During the year ended December 31, 2013, Generation recorded an increase in Operating and maintenance expense of $13 million. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2013.

(b)	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.

(c)	For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

(d)

During the year ended December 31, 2014, Generation, ComEd, PECO and BGE recorded $1 million, $1 million, $1 million, and $1 million, respectively, as the current portion of the ARO. During December 31, 2013 Generation, ComEd, PECO and BGE recorded $0 million, $2 million, $1 million, and $0 million, respectively, as the current portion of the ARO. This is included in Other current liabilities on the Registrants’ respective Consolidated Balance Sheets.

(e)	Represents AROs related to generating stations classified as held for sale as of December 31, 2014. See Note 4—Mergers, Acquisitions, and Dispositions for further information.

(f)	Reflects a reduction to the ARO resulting primarily from the sales of the Keystone and Conemaugh generating stations. See Note 4—Mergers, Acquisitions, and Dispositions for further information.

16. Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)

As of December 31, 2014, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. The table below shows the pension and postretirement benefit plans in which each operating company participated at December 31, 2014.

On April 1, 2014, as a result of the consolidation of CENG into Generation, the obligations associated with CENG’s pension and other postretirement plans are reflected in the disclosures below based on an April 1, 2014 valuation adjusted for subsequent activity. Exelon assumed sponsorship of the CENG pension and other postretirement benefit plans in the third quarter of 2014 when the employees transferred to Exelon. CENG will fund the underfunded balances of the pension and other postretirement benefit plans measured at July 14, 2014 on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG. Payments received from CENG related to the funded plans will be contributed to the appropriate benefit trusts.

386

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Operating Company
Name of Plan:	Generation	ComEd	PECO	BGE	BSC
*Qualified Pension Plans:*
Exelon Corporation Retirement Program^(a)	X	X	X	X	X
Exelon Corporation Cash Balance Pension Plan^(a)	X	X	X	X	X
Exelon Corporation Pension Plan for Bargaining Unit Employees^(a)	X	X			X
Exelon New England Union Employees Pension Plan^(a)	X
Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek^(a)	X	X			X
Pension Plan of Constellation Energy Group, Inc.^(b)	X	X	X	X	X
Pension Plan of Constellation Energy Nuclear Group, LLC^(c)	X			X	X
Nine Mile Point Pension Plan^(c)	X				X
Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B^(b)	X

*Non-Qualified Pension Plans:*
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan^(a)	X	X	X		X
Exelon Corporation Supplemental Management Retirement Plan^(a)	X	X	X	X	X
Constellation Energy Group, Inc. Senior Executive Supplemental Plan^(b)	X			X	X
Constellation Energy Group, Inc. Supplemental Pension Plan^(b)	X			X	X
Constellation Energy Group, Inc. Benefits Restoration Plan^(b)	X			X	X
Constellation Nuclear Plan, LLC Executive Retirement Plan^(c)	X				X
Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan^(c)	X				X
Baltimore Gas & Electric Company Executive Benefit Plan^(b)	X			X	X
Baltimore Gas & Electric Company Manager Benefit Plan^(b)	X			X	X

*Other Postretirement Benefit Plans:*
PECO Energy Company Retiree Medical Plan^(a)	X	X	X	X	X
Exelon Corporation Health Care Program^(a)	X	X		X	X
Exelon Corporation Employees’ Life Insurance Plan^(a)	X	X	X	X	X
Constellation Energy Group, Inc. Retiree Medical Plan^(b)	X	X	X	X	X
Constellation Energy Group, Inc. Retiree Dental Plan^(b)	X			X	X
Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan^(b)	X	X	X	X	X
Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan^(b)	X
Exelon New England Union Post-Employment Medical Savings Account Plan^(a)	X
Retiree Medical Plan of Constellation Energy Nuclear Group LLC^(c)	X			X	X
Retiree Dental Plan of Constellation Energy Nuclear Group LLC^(c)	X			X	X
Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees^(c)	X				X

(a)	These plans are collectively referred to as the Legacy Exelon plans.

(b)	These plans are collectively referred to as the Legacy Constellation Energy Group (CEG) Plans.

(c)	These plans are collectively referred to as the Legacy CENG plans.

387

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 OPEB plans as an asset or liability on its balance sheet, with offsetting entries to Accumulated other comprehensive income (AOCI) and regulatory assets (liabilities), in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31.

During the first quarter of 2014, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $35 million and an increase to the other postretirement benefit obligation of $12 million. Additionally, Accumulated other comprehensive loss (AOCL) increased by approximately $12 million (after tax), regulatory assets increased by approximately $34 million, and regulatory liabilities increased by approximately $5 million. During the second quarter of 2014, Exelon received an updated valuation for the remainder of its pension and other postretirement obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $13 million and an increase to the other postretirement benefit obligation of $3 million. Additionally, AOCL increased by approximately $1 million (after tax) and regulatory assets increased by approximately $15 million.

In April 2014, Exelon announced plan design changes for certain other postretirement benefit plans, which required an interim remeasurement of the benefit obligation for those plans using assumptions as of April 30, 2014, including updated discount rates and asset values. The remeasurement resulted in a decrease to Exelon’s non-pension postretirement benefit obligations, regulatory assets, and AOCL of approximately $790 million, $240 million, and $259 million (after tax), respectively, and an increase in regulatory liabilities of approximately $125 million.

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
	2014			2013			2014			2013
Change in benefit obligation:
Net benefit obligation at beginning of year	$	15,459		$	16,800		$	4,451		$	4,820
Service cost		293			317			117			162
Interest cost		749			650			186			194
Plan participants’ contributions		—			—			42			34
Actuarial loss (gain)		2,095			(1,363	)		502			(551	)
Plan amendments		—			1			(1,012	)		15
Acquisitions/divestitures^(a)		594			—			142			—
Curtailments		(8	)		—			—			—
Settlements		(30	)		(69	)		—			—
Gross benefits paid		(896	)		(877	)		(231	)		(223	)

Net benefit obligation at end of year	$	18,256		$	15,459		$	4,197		$	4,451

388

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Change in plan assets:
Fair value of net plan assets at beginning of year	$	13,571		$	13,357		$	2,238		$	2,135
Actual return on plan assets		1,443			821			90			209
Employer contributions		332			339			291			83
Plan participants’ contributions		—			—			42			34
Benefits paid		(896	)		(877	)		(231	)		(223	)
Acquisitions/divestitures^(a)		454			—			—			—
Settlements		(30	)		(69	)		—			—

Fair value of net plan assets at end of year	$	14,874		$	13,571		$	2,430		$	2,238

(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014. See Note 5—Investment in Constellation Energy Nuclear Group, LLC for further information.

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:


	Pension Benefits				Other Postretirement Benefits
	2014		2013		2014		2013
Other current liabilities	$	16	$	12	$	25	$	23
Pension obligations		3,366		1,876		—		—
Non-pension postretirement benefit obligations		—		—		1,742		2,190

Unfunded status (net benefit obligation less net plan assets)	$	3,382	$	1,888	$	1,767	$	2,213

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.

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
	2014		2013
Projected benefit obligation	$	18,256	$	15,452
Fair value of net plan assets		14,874		13,564


	ABO in excess of plan assets
	2014		2013
Projected benefit obligation	$	18,256	$	15,452
Accumulated benefit obligation		17,191		14,552
Fair value of net plan assets		14,874		13,564

389

Combined Notes to Consolidated Financial Statements—(Continued)

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

On a PBO basis, the plans were funded at 81% at December 31, 2014 compared to 88% at December 31, 2013. On an ABO basis, the plans were funded at 87% at December 31, 2014 compared to 93% at December 31, 2013. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.

Components of Net Periodic Benefit Costs

The majority of the 2014 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.80%. Certain of the pension plans were remeasured as of October 31, 2014 using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.95%. Costs incurred during the year ended December 31, 2014 reflect the impact of this remeasurement. The majority of the 2014 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.59% for funded plans and a discount rate of 4.90% for all plans. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for December 31, 2014 reflect the impact of this remeasurement.

On July 14, 2014 Exelon became the sponsor of the pension and other postretirement plans formerly sponsored by CENG. The components of cost for the CENG plans are included in the table below for the period from April 1, 2014 to December 31, 2014, and reflect the valuation performed on April 1, 2014 upon consolidation of CENG. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC for further details on the consolidation of CENG. The 2014 pension benefit cost for these plans is calculated using an expected long-term rate of return on plan assets of 7.75% and discount rates ranging from 3.60%—4.30%. The majority of the 2014 other postretirement benefit cost for the CENG plans is calculated using a discount rate of 4.55%.

A portion of the net periodic benefit cost for all pension and OPEB plans are capitalized within each of the Registrant’s Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2014, 2013 and 2012.


	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	293		$	317		$	280		$	117		$	162		$	156
Interest cost		749			650			698			186			194			205
Expected return on assets		(994	)		(1,015	)		(988	)		(154	)		(132	)		(115	)
Amortization of:
Transition obligation		—			—			—			—			—			11
Prior service cost (credit)		14			14			15			(122	)		(19	)		(17	)
Actuarial loss		420			562			450			50			83			81
Curtailment benefits		—			—			—			—			—			(7	)
Settlement charges		2			9			31			—			—			—
Contractual termination benefits^(a)		—			—			14			—			—			6

Net periodic benefit cost	$	484		$	537		$	500		$	77		$	288		$	320

(a)	ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in 2012.

390

Combined Notes to Consolidated Financial Statements—(Continued)

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

Through Exelon’s postretirement benefit plans, the Registrants provide retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (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 (Part D subsidy). Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans meets the requirements for the subsidy. In December 2011, the Company decided that beginning in 2013, it would no longer elect to take the direct Part D subsidy. This resulted in a $17 million increase in cost for the year ended December 31, 2012 related to the amortization of an actuarial loss. Beginning in 2013, eligible employees are offered an Employee Group Waiver Plan (EGWP), a standard Medicare Part D Plan, with a supplemental “wrap,” which contains a wraparound prescription drug design that allows the company to provide benefits above those available under the EGWP.

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 (liabilities) for the years ended December 31, 2014, 2013 and 2012 for all plans combined.


	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities):
Current year actuarial (gain) loss	$	1,639		$	(1,169	)	$	1,693		$	561		$	(628	)	$	304
Amortization of actuarial loss		(420	)		(562	)		(450	)		(50	)		(83	)		(81	)
Current year prior service (credit) cost		—			—			1			(1,012	)		15			(109	)
Amortization of prior service (cost) credit		(14	)		(14	)		(15	)		122			19			17
Current year transition (asset) obligation		—			—			—			—			—			1
Amortization of transition asset (obligation)		—			—			—			—			—			(11	)
Curtailments		—			—			(10	)		—			—			(1	)
Settlements		(2	)		(8	)		(31	)		—			—			—

Total recognized in AOCI and regulatory assets (liabilities)^(a)	$	1,203		$	(1,753	)	$	1,188		$	(379	)	$	(677	)	$	120

(a)

Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million loss related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million loss related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012.

391

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 gross accumulated other comprehensive loss and regulatory assets (liabilities) that have not been recognized as components of periodic benefit cost at December 31, 2014 and 2013, respectively, for all plans combined:


	Pension Benefits				Other Postretirement Benefits
	2014		2013		2014			2013
Prior service cost (credit)	$	49	$	62	$	(963	)	$	(73	)
Actuarial loss		7,407		6,192		985			474

Total^(a)	$	7,456	$	6,254	$	22		$	401

(a)

Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. Of the $22 million related to other postretirement benefits, $22 million is included in regulatory assets (liabilities) at December 31, 2014. Of the $6,254 million related to pension benefits, $3,523 million and $2,731 million are included in AOCI and regulatory assets, respectively, at December 31, 2013. Of the $401 million related to other postretirement benefits, $161 million and $240 million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2013.

The following table provides the components of Exelon’s AOCI and regulatory assets at December 31, 2014 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2015. 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, 2015 and actual claims activity as of December 31, 2014. The valuation is expected to be completed in the first quarter of 2015 for the majority of the benefit plans.


	Pension Benefits		Other Postretirement Benefits
Prior service cost (credit)	$	13	$	(175	)
Actuarial loss		562		74

Total^(a)	$	575	$	(101	)

(a)

Of the $575 million related to pension benefits at December 31, 2014, $329 million and $246 million are expected to be amortized from AOCI and regulatory assets in 2015, respectively. Of the $101 million related to other postretirement benefits at December 31, 2014, $(51) million and $(50) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2015, 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 EROA, 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 EROA, 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.

392

Combined Notes to Consolidated Financial Statements—(Continued)

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

Mortality. For the December 31, 2014 actuarial valuation, Exelon changed its assumption of mortality to reflect more recent expectations of future improvements in life expectancy. The change was supported through completion of an experience study and supplemental analyses performed by its actuaries. The change in assumption resulted in increases of $361 million and $117 million in the pension and other postretirement benefits obligations, respectively.

The following assumptions were used to determine the benefit obligations for the plans at December 31, 2014, 2013 and 2012. 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

2014

2013

2012

2014

2013

2012

Discount rate

3.94

4.80

3.92

4.90

4.00

Rate of compensation increase

^(a)

^(b)

^(c)

^(a)

^(b)

^(c)

Mortality table

RP-2000
table with
Scale BB-2D
improvements
(adjusted)

RP-2000
table with
Scale AA
improvements

RP-2000
table with
Scale BB-2D
improvements
(adjusted)

RP-2000
table with
Scale AA
improvements

Health care cost trend on covered charges

N/A

6.00%
decreasing

ultimate

trend of

5.00% in

2017

6.00%

decreasing

ultimate

trend of

5.00% in

2017

6.50%

decreasing

ultimate

trend of

5.00% in

2017

(a)	3.25% for 2015-2019 and 3.75% thereafter.

(b)	3.25% for 2014-2018 and 3.75% thereafter.

(c)	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, 2014, 2013 and 2012:

Pension Benefits

Other Postretirement Benefits

2014

2013

2012

2014

2013

2012

Discount rate

4.80

%^(a)

3.92

%^(b)

4.74

%^(c)

4.90

%^(a)

4.00

%^(b)

4.80

%^(c)

Expected return on plan assets

7.00

%^(d)

7.50

%^(d)

7.50

%^(d)

6.59

%^(d)

6.45

%^(d)

6.68

%^(d)

Rate of compensation increase

^(e)

^(f)

3.75

^(e)

^(f)

3.75

Mortality table

RP-2000
table with
Scale AA
improvements

Health care cost trend on covered charges

N/A

6.00%

decreasing to

ultimate trend
of 5.00% in
2017

6.50%

decreasing to

ultimate trend

of 5.00% in

2017

6.50%

decreasing to

ultimate trend
of 5.00% in

2017

(a)	The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were

393

Combined Notes to Consolidated Financial Statements—(Continued)

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

remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5—Investment in Constellation Energy Nuclear Group, LLC for further information.

(b)

The discount rates above represent the initial discount rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these measurements.

(c)

The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2012. 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 of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurements.

(d)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.

(e)	3.25% for 2014-2018 and 3.75% thereafter.

(f)	3.25% for 2013-2017 and 3.75% thereafter.

Assumed health care cost trend rates impact the costs reported for Exelon’s other postretirement benefit plans for participants populations with plan designs that do not have a cap on cost growth. 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 2014 total service and interest cost components	$	35
on postretirement benefit obligation at December 31, 2014		162
Effect of a one percentage point decrease in assumed health care cost trend:
on 2014 total service and interest cost components		(24	)
on postretirement benefit obligation at December 31, 2014		(113	)

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 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.

394

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
	2014^(c)		2013		2012		2014		2013		2012 ^(a)
Generation	$	173	$	119	$	48	$	124	$	30	$	135
ComEd		122		118		25		125		4		119
PECO		11		11		13		5		20		33
BGE^(b)		—		—		—		17		24		12
BSC^(d)		26		91		63		20		5		24

Exelon	$	332	$	339	$	149	$	291	$	83	$	323

(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. Effective January 1, 2013, Exelon is no longer receiving this subsidy.

(b)

BGE’s other postretirement benefit payments for 2012 exclude $4 million, of other postretirement benefit payments made by BGE prior to the closing of the Constellation merger on March 12, 2012. These pre-Constellation merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statements.

(c)	Exelon’s and Generation’s pension contributions include $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG.

(d)	Includes $9 million, $72 million, and $13 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2014, 2013, and 2012, 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, until the plan is fully funded on an ABO basis, the projected contribution reflects a funding strategy of contributing $250 million. This level funding strategy helps minimize volatility of future period required pension contributions.

Exelon plans to contribute $447 million to its qualified pension plans in 2015, of which Generation, ComEd, PECO, and BGE will contribute $230 million, $138 million, $40 million, and $1 million, respectively. Exelon’s and Generation’s expected qualified pension plan contributions above include $36 million related to the legacy CENG plans that will be funded by CENG as provided in an EMA between Exelon and CENG.

Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon plans to make non-qualified pension plan benefit payments of $15 million in 2015, of which Generation, ComEd, PECO, and BGE will make payments of $6 million, $1 million, $1 million and $1 million, respectively.

395

Combined Notes to Consolidated Financial Statements—(Continued)

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

Unlike the qualified pension plans, other postretirement plans are not subject to statutory minimum contribution requirements. Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). In 2015, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $37 million in 2015, of which Generation, ComEd, PECO, and BGE expect to contribute $17 million, $2 million, $0 million, and $17 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, 2014 were:


	Pension Benefits		Other Postretirement Benefits
2015	$	1,064	$	217
2016		962		223
2017		979		230
2018		1,004		236
2019		1,032		247
2020 through 2024		5,825		1,373

Total estimated future benefit payments through 2024	$	10,866	$	2,526

Allocation to Exelon Subsidiaries

Generation, ComEd, PECO, and BGE account for their participation in Exelon’s pension and other postretirement benefit plans by applying multi-employer 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. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon has allocated 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. Pension and postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. Beginning in 2015, Exelon is allocating costs related to its legacy Exelon pension and postretirement benefit plans to its subsidiaries based on both active and retired employee participation and contributions are being allocated based on accounting cost. The impact of this allocation methodology change is not material to any Registrant. For legacy CEG and legacy CENG plans, components of pension and other postretirement benefit costs and contributions have been, and will continue to be, allocated to the subsidiaries based on employee participation (both active and retired).

396

Combined Notes to Consolidated Financial Statements—(Continued)

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

The amounts below were included in capital expenditures and Operating and maintenance expense for the years ended December 31, 2014, 2013 and 2012, respectively, for Generation’s, ComEd’s, PECO’s, BSC’s and BGE’s allocated portion of the pension and postretirement benefit plan costs. 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
2014	$	250	$	162	$	36	$	46	$	67		561
2013		347		309		43		71		55		825
2012		341		282		50		99		60		820

(a)

These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of December 31, 2012, ComEd and BGE each reported a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge.

(b)

The amounts included in capital and Operating and maintenance expense for the years ended December 31, 2012 include $12 million in costs incurred prior to the closing of the Constellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year ended December 31, 2012.

(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 as of December 31, 2012.

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 a liability hedging 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. 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 7.00% and 6.46% to estimate its 2015 pension and other postretirement benefit costs, respectively.

Exelon’s pension and other postretirement benefit plan target asset allocations and December 31, 2014 and 2013 asset allocations were as follows:

Pension Plans


				Percentage of Plan Assets at December 31,
Asset Category	Target Allocation			2014			2013
Equity securities		32	%		33	%		35	%
Fixed income securities		37	%		37			37
Alternative investments^(a)		31	%		30			28

Total					100	%		100	%

397

Combined Notes to Consolidated Financial Statements—(Continued)

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

Other Postretirement Benefit Plans


				Percentage of Plan Assets at December 31,
Asset Category	Target Allocation			2014			2013
Equity securities		41	%		42	%		45	%
Fixed income securities		34	%		34			37
Alternative investments^(a)		25	%		24			18

Total					100	%		100	%

(a)	Alternative investments include private equity, hedge funds and real estate.

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, 2014. 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, 2014, there were no significant concentrations (defined as greater than 10% 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, 2014 and 2013:


At December 31, 2014 ^(a)	Level 1		Level 2			Level 3		Total
Pension plan assets
Cash equivalents	$	1	$	—		$	—	$	1
Equities:
Domestic		1,556		1,133			2		2,691
Foreign		1,705		316			—		2,021

Equities subtotal		3,261		1,449			2		4,712

Fixed income:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		1,051		88			—		1,139
Debt securities issued by states of the United States and by political subdivisions of the states		—		80			—		80
Corporate debt securities		—		3,125			120		3,245
Other		—		942			152		1,094
Derivative instruments^(b):
Assets		—		4			—		4
Liabilities		—		(16	)		—		(16	)

Fixed income subtotal		1,051		4,223			272		5,546

Private equity		—		—			904		904
Hedge funds		—		1,355			1,329		2,684
Real estate		243		—			744		987

Pension plan assets subtotal		4,556		7,027			3,251		14,834

398

Combined Notes to Consolidated Financial Statements—(Continued)

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


At December 31, 2014 ^(a)	Level 1		Level 2		Level 3		Total
Other postretirement benefit plan assets
Cash equivalents		11		—		—		11
Equities:
Domestic		296		378		—		674
Foreign		184		147		—		331

Equities subtotal		480		525		—		1,005

Fixed income:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		15		59		—		74
Debt securities issued by states of the United States and by political subdivisions of the states		—		197		—		197
Corporate debt securities		—		42		—		42
Other		253		272		—		525

Fixed income subtotal		268		570		—		838

Hedge funds		—		339		110		449
Real estate		8		—		116		124

Other postretirement benefit plan assets subtotal		767		1,434		226		2,427

Total pension and other postretirement benefit plan assets ^(c)	$	5,323	$	8,461	$	3,477	$	17,261


At December 31, 2013 ^(a)	Level 1		Level 2			Level 3		Total
Pension plan assets
Equities:
Domestic	$	1,587	$	865		$	2	$	2,454
Foreign		1,773		302			—		2,075

Equities subtotal		3,360		1,167			2		4,529

Fixed income:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		908		99			—		1,007
Debt securities issued by states of the United States and by political subdivisions of the states		—		88			—		88
Foreign debt securities		—		205			—		205
Corporate debt securities		—		2,927			41		2,968
Other		5		899			—		904
Derivative instruments^(b):
Assets		—		7			—		7
Liabilities		—		(134	)		—		(134	)

Fixed income subtotal		913		4,091			41		5,045

Private equity		—		—			806		806
Hedge funds		—		1,266			1,039		2,305
Real estate		264		2			582		848

Pension plan assets subtotal		4,537		6,526			2,470		13,533

399

Combined Notes to Consolidated Financial Statements—(Continued)

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


At December 31, 2013 ^(a)	Level 1		Level 2		Level 3		Total
Other postretirement benefit plan assets
Cash equivalents		51		—		—		51
Equities:
Domestic		296		345		—		641
Foreign		154		170		—		324

Equities subtotal		450		515		—		965

Fixed income:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		17		46		—		63
Debt securities issued by states of the United States and by political subdivisions of the states		—		149		—		149
Foreign debt securities		—		2		—		2
Corporate debt securities		—		50		—		50
Other		305		225		—		530

Fixed income subtotal		322		472		—		794

Private equity		—		—		2		2
Hedge funds		—		295		4		299
Real estate		8		5		109		122

Other postretirement benefit plan assets subtotal		831		1,287		115		2,233

Total pension and other postretirement benefit plan assets ^(c)	$	5,368	$	7,813	$	2,585	$	15,766

(a)	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)

Derivative instruments have a total notional amount of $1,491 million and $2,651 million at December 31, 2014 and 2013, 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)

Excludes net assets of $42 million and $43 million at December 31, 2014 and 2013, 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.

400

Combined Notes to Consolidated Financial Statements—(Continued)

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

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, 2014 and 2013:


	Hedge funds			Private equity			Real estate			Fixed income			Equities		Total
Pension Assets
Balance as of January 1, 2014	$	1,039		$	806		$	582		$	41		$	2	$	2,470
Actual return on plan assets:
Relating to assets still held at the reporting date		77			112			83			7			—		279
Relating to assets sold during the period		3			—			—			—			—		3
Purchases, sales and settlements:
Purchases		311			173			136			227			—		847
Sales		(38	)		—			(19	)		(3	)		—		(60	)
Settlements^(a)		(33	)		(203	)		(65	)		—			—		(301	)
Transfers into (out of) Level 3 ^(b)(c)		(30	)		16			27			—			—		13

Balance as of December 31, 2014	$	1,329		$	904		$	744		$	272		$	2	$	3,251

Other Postretirement Benefits
Balance as of January 1, 2014	$	4		$	2		$	109		$	—		$	—	$	115
Actual return on plan assets:
Relating to assets still held at the reporting date		1			—			13			—			—		14
Purchases, sales and settlements:
Purchases		109			1			1			—			—		111
Sales		(4	)		(2	)		(7	)		—			—		(13	)
Settlements^(a)		—			(1	)		—			—			—		(1	)

Balance as of December 31, 2014	$	110		$	—		$	116		$	—		$	—	$	226

401

Combined Notes to Consolidated Financial Statements—(Continued)

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


	Hedge funds			Private equity			Real estate			Fixed income		Equities		Total
Pension Assets
Balance as of January 1, 2013	$	1,235		$	754		$	426		$	—	$	—	$	2,415
Actual return on plan assets:
Relating to assets still held at the reporting date		143			86			63			—		—		292
Relating to assets sold during the period		3			—			(4	)		—		—		(1	)
Purchases, sales and settlements:
Purchases		360			123			226			41		2		752
Sales		(76	)		—			(91	)		—		—		(167	)
Settlements^(a)		(3	)		(157	)		(38	)		—		—		(198	)
Transfers into (out of) Level 3^(c)		(623	)		—			—			—		—		(623	)

Balance as of December 31, 2013	$	1,039		$	806		$	582		$	41	$	2	$	2,470

Other Postretirement Benefits
Balance as of January 1, 2013	$	12		$	1		$	95		$	—	$	—	$	108
Actual return on plan assets:
Relating to assets still held at the reporting date		1			—			11			—		—		12
Purchases, sales and settlements:
Purchases		—			1			3			—		—		4
Sales		(1	)		—			—			—		—		(1	)
Settlements ^(a)		(4	)		—			—			—		—		(4	)
Transfers into (out of) Level 3 ^(c)		(4	)		—			—			—		—		(4	)

Balance as of December 31, 2013	$	4		$	2		$	109		$	—	$	—	$	115

(a)	Represents cash settlements only.

(b)	In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million.

(c)

As of January 1, 2014 and January 1, 2013, hedge fund investments that contained redemption restrictions limiting Exelon’s ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2014 and December 31, 2013, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $43 million and $627 million in 2014 and 2013 respectively.

There were no transfers between Level 1 and Level 2 during the twelve months ended December 31, 2014 for the pension and other postretirement benefit plan assets.

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.

Equities. Equities consist of individually held equity securities, equity mutual funds and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from

402

Combined Notes to Consolidated Financial Statements—(Continued)

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

market exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including rights and warrants, 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. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

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 the plans’ 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 equity 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. For fixed income securities, which consist primarily of corporate debt securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, 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. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, 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

Other fixed income investments primarily consist of fixed income commingled funds, mutual funds, and short-term investment funds, which 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 NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Certain fixed income commingled funds are valued using the NAV per fund share, which is based on the valuation of the underlying investments and include significant unobservable inputs. These funds have been categorized as Level 3.

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.

403

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 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 NAV 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.

As of December 31, 2014, Exelon has outstanding commitments to invest in private equity and real estate investments of approximately $825 million. These commitments will be funded by Exelon’s existing pension and other postretirement benefit trusts.

Defined Contribution Savings Plan (Exelon, Generation, ComEd, PECO and BGE)

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2014, 2013 and 2012:


For the Year Ended December 31,	Exelon		Generation		ComEd		PECO		BGE ^(a)		BSC ^(b)
2014	$	103	$	51	$	26	$	8	$	8	$	10
2013		85		40		22		8		8		7
2012		67		30		19		7		7		5

(a)	BGE’s matching contributions for the year ended December 31, 2012 include $1 million incurred prior to the closing of the Constellation merger on March 12, 2012. These costs are not included in Exelon’s matching contributions for the year ended December 31, 2012.

(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, or BGE amounts above.

404

Combined Notes to Consolidated Financial Statements—(Continued)

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

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

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.

CENG Integration-Related Severance

In connection with the Master Agreement, Generation and CENG recorded a severance accrual in the fourth quarter of 2013 for the anticipated employee position reductions as a result of the integration of $2 million and $16 million, respectively. The majority of these positions are corporate and support positions at CENG. On April 1, 2014, the date the NOSA was executed, Generation consolidated the $19 million CENG severance liability pursuant to the Master Agreement. For the years ended December 31, 2014 and 2013, respectively, Exelon and Generation recorded severance benefit costs associated with the employee reductions of $3 million and $2 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The estimated amount of severance payments associated with this plan is expected to be approximately $24 million. As of December 31, 2014, management recorded its best estimate of severance benefits, which could be adjusted through the completion of the integration process if additional employee position reductions are identified or if employees resign prior to their agreed upon service termination date. Estimated costs to be incurred after December 31, 2014 are not material.

Amounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration:


Year Ended December 31, 2014 Severance Liability	Exelon and Generation
Balance at December 31, 2013	$	2
Integration of CENG ^(a)		19
Severance charges		3
Payments		(11	)

Balance at December 31, 2014	$	13

(a)

Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.

Cash payments under the severance plan began in 2014. Substantially all cash payments under the plan are expected to be made by the end of 2015.

Constellation Merger-Related Severance

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

405

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 for the twelve months ended December 31, 2014 and 2013 is not material. Estimated costs to be incurred after December 31, 2014 are not immaterial.

For the year ended December 31, 2012, the Registrants recorded the following severance benefit costs associated with identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, except for those costs that were capitalized as regulatory assets related to ComEd and BGE:


Year Ended December 31, 2012 Severance Benefits ^(a)	Exelon ^(b)		Generation		ComEd ^(b)		PECO		BGE ^(b)
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)	Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. 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:


Severance liability	Exelon			Generation			ComEd			PECO		BGE
Balance at December 31, 2012	$	111		$	33		$	1		$	—	$	11
Severance charges^(a)		5			1			—			—		—
Stock compensation		1			—			—			—		—
Payments		(64	)		(24	)		(1	)		—		(5	)

Balance at December 31, 2013	$	53		$	10		$	—		$	—	$	6

Payments		(41	)		(7	)		—			—		(4	)

Balance at December 31, 2014	$	12		$	3		$	—		$	—	$	2

(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for under Exelon’s ongoing severance plan. One-time termination benefits were not material for the years ended December 31, 2014 and December 31, 2013.

Substantially all cash payments under the plan are expected to be made by the end of 2016.

406

Combined Notes to Consolidated Financial Statements—(Continued)

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

Ongoing Severance Plans

The Registrants provide severance, health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business, which were not directly related to the merger with Constellation or with the integration of CENG. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.

For the years ended December 31, 2014, 2013, and 2012, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:


Severance Benefits ^(a)	Exelon		Generation		ComEd		PECO		BGE
Severance Charges—2014	$	7	$	5	$	1	$	—	$	1
Severance Charges—2013		18		16		2		—		—
Severance Charges—2012		19		14		2		1		3

(a)	The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material.

(b)	The amount of ongoing severance for Generation for the year ended December 31, 2014 includes a $3 million severance reserve as a result of anticipated employee position reductions due to recent acquisitions.

The severance liability balances associated with these ongoing severance benefits as of December 31, 2014 and 2013 are not material.

18. Preferred and Preference Securities (Exelon, ComEd, PECO and BGE)

At December 31, 2014 and 2013, 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, 2014 and 2013, 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.

On May 1, 2013, PECO redeemed all of its outstanding preferred securities. PECO had $87 million of cumulative preferred securities that were redeemable at its option at any time for the redemption price established when each series was issued. The redemption premium was treated as a reduction to Net income to arrive at Net income attributable to common shareholders utilized in the calculation of the earnings per share for Exelon.

At December 31, 2014 and 2013, 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

407

Combined Notes to Consolidated Financial Statements—(Continued)

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

•

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)		2014		2013		2014		2013
	Redemption Price ^(a)		Shares Outstanding				Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.00		400,000		400,000	$	40	$	40
6.97%, 1993 Series		100.00		500,000		500,000		50		50
6.70%, 1993 Series		100.00		400,000		400,000		40		40
6.99%, 1995 Series		100.35		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.

19. Common Stock (Exelon, Generation, ComEd, PECO and BGE)

The following table presents common stock authorized and outstanding as of December 31, 2014 and 2013:


					December 31,
					2014		2013
	Par Value		Shares Authorized		Shares Outstanding
Common Stock
Exelon		no par value		2,000,000,000		859,833,343		857,290,484
ComEd		$12.50		250,000,000		127,016,947		127,016,896
PECO		no par value		500,000,000		170,478,507		170,478,507
BGE		no par value		175,000,000		1,000		1,000

ComEd had 73,533 and 73,709 warrants outstanding to purchase ComEd common stock at December 31, 2014 and 2013, 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, 2014 and 2013, 24,511 and 24,570 shares of common stock, respectively, were reserved for the conversion of warrants.

Equity Securities Offering

In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements requiring Exelon to, at its election, prior to October 29, 2015; i) physically settle the transaction through the issuance of 57.5 million shares of its common stock in exchange for net proceeds at the forward price specified in the agreements of between approximately $1.8 billion and $1.9 billion, after consideration of underwriters discount of approximately $60 million and subject to certain adjustments as provided in the forward sales agreement, or ii) net settle the transaction either through the payment of cash or shares of its common stock based on the then current market value of

408

Combined Notes to Consolidated Financial Statements—(Continued)

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

the shares minus the value of the shares at the forward price, net of the underwriters discount and the daily accretion rate. No amounts have or will be recorded in Exelon’s consolidated financial statements with respect to the equity offering until settlement of the forward sale agreements occurs. If Exelon elected to net share settle the contract as of December 31, 2014, Exelon would have been required to issue 4 million shares. If Exelon elects to cash settle the contract, the transaction costs will be recorded as a charge to earnings in the period in which it becomes probable that Exelon will cash settle. Otherwise, all transaction costs will be reflected as a reduction to the value of the common stock issued in Exelon’s Consolidated Balance Sheet. The net proceeds received upon settlement are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes. Until settlement, earnings per share dilution resulting from the forward sales agreement, if any, will be determined under the treasury stock method.

Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. See Note 13—Debt and Credit Agreements for further information on the equity units.

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. In 2008, Exelon management decided to defer indefinitely any share repurchases. Any shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Under the share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2014. During 2014, 2013 and 2012, Exelon had no common stock repurchases.

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2014, there were approximately 16 million shares authorized for issuance under the LTIP. For the years ended December 31, 2014, 2013 and 2012, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

The Compensation Committee of Exelon’s Board of Directors changed the mix of awards granted under the LTIP in 2013 by eliminating stock options in favor of the use of full value shares, consisting of 67% performance shares and 33% restricted stock units. The performance share awards granted in 2013 will cliff vest at the end of a three-year performance period. The performance share awards granted in 2012 and earlier had a one-year performance period and vested ratably over three years. To address the reduction in annual award opportunity resulting from the transition to a three-year cliff vesting performance period, the Compensation Committee also approved a one-time grant of

409

Combined Notes to Consolidated Financial Statements—(Continued)

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

performance share transition awards in 2013, which vested one-third after one year, with the remaining balance vesting over a two-year performance period. These one-time 2013 performance share transition awards will be settled 50% in common stock and 50% in cash, except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain Exelon stock ownership requirements are satisfied. In addition to this change, in 2013 ComEd and in 2014 PECO and BGE transitioned from Exelon stock-based awards to cash award programs with payouts based on the performance of each respective utility. The following tables do not include expense related to these plans as they are not considered stock-based compensation plans under the applicable accounting guidance.

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012:


	Year Ended December 31,
Components of Stock-Based Compensation Expense	2014			2013			2012
Performance share awards	$	59		$	48		$	46
Restricted stock units		61			61			50
Stock options		2			3			15
Other stock-based awards		5			6			4

Total stock-based compensation expense included in operating and maintenance expense		127			118			115
Income tax benefit		(47	)		(44	)		(44	)

Total after-tax stock-based compensation expense	$	80		$	74		$	71

The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2014, 2013 and 2012:


	Year Ended December 31,
Subsidiaries	2014		2013		2012 ^(a)
Generation	$	52	$	48	$	42
ComEd		7		9		11
PECO		3		5		5
BGE		5		6		5
BSC^(b)		60		50		52

Total	$	127	$	118	$	115

(a)

BGE’s stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012. This amount is not included in Exelon’s stock-based compensation expense for the year ended December 31, 2012 shown in the table titled Components of Stock-Based Compensation Expense and the breakout by subsidiary above.

(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, 2014, 2013 and 2012.

410

Combined Notes to Consolidated Financial Statements—(Continued)

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

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the 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, 2014, 2013 and 2012:


	Year Ended December 31,
	2014		2013		2012
Realized tax benefit when exercised/distributed:
Stock options	$	—	$	—	$	3
Restricted stock units		17		11		11
Performance share awards		11		11		7
Stock deferral plan		—		1		—
Excess tax benefits included in other financing activities of Exelon’s
Consolidated Statements of Cash Flows:
Stock options	$	—	$	—	$	2

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock were granted under the LTIP through 2012. Due to changes in the LTIP, there were no stock options granted in 2013 or 2014. For all stock options granted through 2012, the exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant.

The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.

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 year ended 2012:


	Year ended December 31, 2012
Dividend yield		5.28	%
Expected volatility		23.20	%
Risk-free interest rate		1.30	%
Expected life (years)		6.25
Weighted average grant date fair value (per share)		4.18

411

Combined Notes to Consolidated Financial Statements—(Continued)

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

The assumptions above relate to Exelon stock options granted in 2012 and therefore do not include stock options that were converted in connection with the merger with Constellation during the year ended 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.

The following table presents information with respect to stock option activity for the year ended December 31, 2014:


	Shares			Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)		Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2013		21,035,445		$	46.07
Options exercised		(291,805	)		25.27
Options forfeited		(8,886	)		55.78
Options expired		(1,903,787	)		41.47

Balance of shares outstanding at December 31, 2014		18,830,967		$	46.85		4.11	$	29

Exercisable at December 31, 2014 ^(a)		18,398,932		$	47.01		4.04	$	29

(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, 2014, 2013 and 2012:


	Year Ended December 31,
	2014		2013		2012
Intrinsic value^(a)	$	3	$	4	$	19
Cash received for exercise price		7		19		47

(a)	The difference between the market value on the date of exercise and the option exercise price.

412

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2014:


	Shares			Weighted Average Exercise Price (per share)
Nonvested at December 31, 2013 ^(a)		847,118		$	40.22
Vested		(406,197	)		40.21
Forfeited		(8,886	)		55.78

Nonvested at December 31, 2014 ^(a)		432,035		$	39.91

(a)	Excludes 746,140 and 1,348,913 of stock options issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.

At December 31, 2014, $1 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 1.0 year.

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, 2014:


	Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2013 ^(a)		3,386,697		$	34.10
Granted		2,252,574			28.71
Vested		(1,216,016	)		35.36
Forfeited		(86,094	)		31.99
Undistributed vested awards^(b)		(578,943	)		29.17

Nonvested at December 31, 2014 ^(a)		3,758,218		$	31.27

(a)	Excludes 975,116 and 931,628 of restricted stock units issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.

(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2014.

The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2014, 2013 and 2012 was $28.71, $31.06 and $39.94, respectively. At

413

Combined Notes to Consolidated Financial Statements—(Continued)

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

December 31, 2014 and 2013, Exelon had obligations related to outstanding restricted stock units not yet settled of $85 million and $77 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2014, 2013 and 2012, Exelon settled restricted stock units with fair value totaling $43 million, $28 million and $25 million, respectively. At December 31, 2014, $59 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.1 years.

Performance Share Awards

Performance share awards are granted under the LTIP. The 2014 and 2013 performance share awards are being settled 50% in common stock and 50% in cash at the end of the three-year performance period except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. The performance shares granted prior to 2012 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.

The common stock portion of the performance share and one-time 2013 performance share transition awards is considered an equity award and is valued based on Exelon’s stock price on the grant date. The cash portion of the awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.

For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share and one-time performance share transition awards granted to retirement-eligible employees, the value of the performance shares in 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, 2014:


	Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2013 ^(a)		2,014,190		$	32.74
Granted		1,712,085			28.75
Change in performance		98,227			31.85
Vested		(497,714	)		35.05
Forfeited		(29,476	)		30.16
Undistributed vested awards ^(b)		(601,215	)		28.96

Nonvested at December 31, 2014 ^(a)		2,696,097		$	30.62

(a)	Excludes 1,535,791 and 1,411,824 of performance share awards issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.

(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2014.

The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2014, 2013 and 2012 was $28.75, $31.55, and $39.71,

414

Combined Notes to Consolidated Financial Statements—(Continued)

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

respectively. During the years ended December 31, 2014, 2013 and 2012, Exelon settled performance shares with a fair value totaling $27 million, $26 million and $23 million, respectively, of which $13 million, $12 million and $3 million was paid in cash, respectively. As of December 31, 2014, $54 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:


	December 31,
	2014		2013
Current liabilities^(a)	$	28	$	13
Deferred credits and other liabilities^(b)		36		24
Common stock		33		32

Total	$	97	$	69

(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.

20. Earnings Per Share and Equity (Exelon)

Earnings per Share

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders 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 the 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,
	2014		2013		2012
Net income attributable to common shareholders	$	1,623	$	1,719	$	1,160

Weighted average common shares outstanding—basic		860		856		816
Assumed exercise and/or distributions of stock-based awards		4		4		3

Weighted average common shares outstanding—diluted		864		860		819

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 17 million in 2014, 20 million in 2013, and 14 million in 2012. The number of equity units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the year ended December 31, 2014 since issuance. Additionally, there were no forward units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the year ended December 31, 2014 since issuance. Refer to Note 19—Common Stock for further information regarding the equity units and equity forward units.

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, 2014. In 2008, Exelon management decided to defer indefinitely any share repurchases.

415

Combined Notes to Consolidated Financial Statements—(Continued)

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

21. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014 and 2013:


For the Year Ended December 31, 2014	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains and (Losses) on Marketable Securities			Pension and Non-Pension Postretirement Benefit Plan items			Foreign Currency Items			AOCI of Equity Investments			Total
Exelon^(a)
Beginning balance	$	120		$	2		$	(2,260	)	$	(10	)	$	108		$	(2,040	)

OCI before reclassifications		(31	)		(1	)		(498	)		(9	)		11			(528	)
Amounts reclassified from AOCI^(b)		(117	)		2			118			—			(119	)		(116	)

Net current-period OCI		(148	)		1			(380	)		(9	)		(108	)		(644	)

Ending balance	$	(28	)	$	3		$	(2,640	)	$	(19	)	$	—		$	(2,684	)

Generation^(a)
Beginning balance	$	114		$	2		$	—		$	(10	)	$	108		$	214

OCI before reclassifications		(15	)		(1	)		—			(9	)		11			(14	)
Amounts reclassified from AOCI^(b)		(117	)		—			—			—			(119	)		(236	)

Net current-period OCI		(132	)		(1	)		—			(9	)		(108	)		(250	)

Ending balance	$	(18	)	$	1		$	—		$	(19	)	$	—		$	(36	)

PECO^(a)
Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1

OCI before reclassifications		—			—			—			—			—			—

Amounts reclassified from AOCI^(b)		—			—			—			—			—			—


Net current-period OCI		—			—			—			—			—			—


Ending balance	$	—		$	1		$	—		$	—		$	—		$	1

416

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2013	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains and (Losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan items			Foreign Currency Items			AOCI of Equity Investments		Total
Exelon^(a)
Beginning balance	$	368		$	—	$	(3,137	)	$	—		$	2	$	(2,767	)

OCI before reclassifications		29			2		669			(10	)		101		791
Amounts reclassified from AOCI ^(b)		(277	)		—		208			—			5		(64	)

Net current-period OCI		(248	)		2		877			(10	)		106		727

Ending balance	$	120		$	2	$	(2,260	)	$	(10	)	$	108	$	(2,040	)

Generation^(a)
Beginning balance	$	512		$	—	$	—		$	—		$	1		513

OCI before reclassifications		15			2		—			(10	)		102		109
Amounts reclassified from AOCI ^(b)		(413	)		—		—			—			5		(408	)

Net current-period OCI		(398	)		2		—			(10	)		107		(299	)

Ending balance	$	114		$	2	$	—		$	(10	)	$	108	$	214

PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—	$	1

OCI before reclassifications		—			—		—			—			—		—
Amounts reclassified from AOCI ^(b)		—			—		—			—			—		—

Net current-period OCI		—			—		—			—			—		—

Ending balance	$	—		$	1	$	—		$	—		$	—	$	1

(a)	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

(b)	See next tables for details about these reclassifications.

417

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd, PECO, and BGE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 2014 and 2013. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2014 and 2013:


For the Year Ended December 31, 2014
Details about AOCI components	Items reclassified out of AOCI ^(a)						Affected line item in the Statements of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Energy related hedges	$	195		$	195		Operating revenues

		195			195		Total before tax
		(78	)		(78	)	Tax expense

	$	117		$	117		Net of tax

Gains and (losses) on available for sale securities
Other available securities for sale	$	(2	)	$	—		Other Income and Deductions

	$	(2	)	$	—		Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	46		$	—
Actuarial losses^(b)		(239	)		—

		(193	)		—		Total before tax
		75			—		Tax benefit

	$	(118	)	$	—		Net of tax

Equity investments
Sale of equity method investment	$	5		$	5
Reversal of CENG equity method AOCI		193			193		Equity in losses of unconsolidated affiliates

		198			198		Total before tax
		(79	)		(79	)	Tax expense

	$	119		$	119		Net of tax

Total Reclassifications	$	116		$	236		Net of tax

418

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the Year Ended December 31, 2013
Details about AOCI components	Items reclassified out of AOCI ^(a)						Affected line item in the Statements of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Energy related hedges	$	464		$	683		Operating revenues
Other cash flow hedges		(3	)		—		Interest expense

		461			683		Total before tax
		(184	)		(270	)	Tax expense

	$	277		$	413		Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	(2	)	$	—
Actuarial losses^(b)		(339	)		—
Deferred compensation unit plan^(c)		(1	)		—

		(342	)		—		Total before tax
		134			—		Tax benefit

	$	(208	)	$	—		Net of tax

Equity investments
Capital activity	$	(8	)	$	(8	)	Equity in losses of unconsolidated affiliates

		(8	)		(8	)	Total before tax
		3			3		Tax benefit

	$	(5	)	$	(5	)	Net of tax

Total Reclassifications	$	64		$	408		Net of tax

(a)	Amounts in parenthesis represent a decrease in net income.

(b)	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 16—Retirement Benefits for additional details).

(c)	Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.

419

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2014 and 2013:


	For the Years Ended December 31,
	2014			2013			2012
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	19		$	—		$	(1	)
Actuarial loss reclassified to periodic cost		(93	)		(133	)		(110	)
Transition obligation reclassified to periodic cost		—			—			(2	)
Pension and non-pension postretirement benefit plans valuation adjustment		317			(430	)		237
Change in unrealized loss on cash flow hedges		96			166			68
Change in marketable securities		—			—			1
Change in unrealized income on equity investments		73			(71	)		(1	)

Total	$	412		$	(468	)	$	192

Generation
Change in unrealized loss on cash flow hedges	$	84		$	262		$	262
Change in unrealized income on equity investments		73			(72	)		1

Total	$	157		$	190		$	263

22. Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)

Nuclear Insurance

Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

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, 2014, the current liability limit per incident was $13.6 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 September 10, 2013. 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 $13.2 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 $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG’s related liability.

420

Combined Notes to Consolidated Financial Statements—(Continued)

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

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.6 billion limit for a single incident.

As part of the execution of NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG.

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. NEIL declared a distribution for 2014 and 2013, of which Generation’s portion was $18.3 million and $18.5 million respectively. No distributions were declared in 2012. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). 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, 2014, the current maximum aggregate annual retrospective premium obligation for Generation is approximately $319 million. 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.

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. 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 unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. 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.

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.

421

Combined Notes to Consolidated Financial Statements—(Continued)

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

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 historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. For the year ended December 31, 2014, and for the year ended December 31, 2013, Generation incurred expense of $49 million and $136 million, respectively, in SNF disposal fees, recorded in Purchased power and fuel expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, including Exelon’s share of Salem and net of co-owner reimbursements (not including such fees incurred by CENG). Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. 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 has been, and is expected to 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 devised a new strategy for long-term SNF management. A Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing 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.

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, Quad Cities, Ginna, Nine Mile Point, and Calvert Cliffs stations.

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. Settlement agreements pertaining to Calvert Cliffs and Ginna were executed during 2011, and Nine Mile Point during 2012, (the “DOE Settlement Agreements”), as amended in 2014 for Calvert Cliffs and Nine Mile Point, under which the government has agreed to reimburse the costs associated with SNF storage expended or to be expended through 2016 as a result of the DOE delays. The DOE Settlement Agreement is expected to be amended for Ginna in a similar manner as needed. Generation, including CENG, 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.

422

Combined Notes to Consolidated Financial Statements—(Continued)

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

Under the settlement agreement, Generation has received cumulative cash reimbursements for costs incurred as follows:


	Total		Net ^(a)
Cumulative cash reimbursements ^(b)	$	836	$	702

(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.

(b)	Includes $33 million and $30 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.

As of December 31, 2014, and 2013, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:


	December 31, 2014			December 31, 2013
DOE receivable—current ^(a)	$	82		$	71
DOE receivable—noncurrent ^(b)		7			—
Amounts owed to co-owners ^(a)(c)		(5	)		(18	)

(a)	Recorded in Accounts receivable, other.

(b)	Recorded in Deferred debits and other assets, other

(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2014, the unfunded SNF liability for the one-time fee with interest was $1,021 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, 2014, was 0.020%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 11—Fair Value of Financial 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

423

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

At December 31, 2014, 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)		REC Purchases ^(b)		Transmission Rights Purchases ^(c)		Total
2015	$	418	$	152	$	20	$	590
2016		283		228		15		526
2017		222		121		15		358
2018		112		29		16		157
2019		117		5		16		138
Thereafter		279		1		35		315

Total	$	1,431	$	536	$	117	$	2,084

(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, 2014, net of fixed capacity payments expected to be received (“capacity offsets”) by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of December 31, 2014, capacity offsets were $132 million, $133 million, $136 million, $137 million, $138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.

(b)	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.

ComEd purchases its expected energy requirements through an ICC approved competitive bidding process administered by the IPA and spot market purchases. See Note 3—Regulatory Matters for further information.

PECO has entered into contracts through a competitive procurement process in order to meet a portion of its default service customers’ electric supply requirements through 2016. See Note 3—Regulatory Matters for further information regarding the DSP Programs.

ComEd is subject to requirements established by the Illinois 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. See Note 3—Regulatory Matters for additional information relating to electric generation procurement, alternative energy resources and energy efficiency programs.

424

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, 2014 are as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
ComEd
Electric supply procurement^(a)	$	620	$	329	$	151	$	140	$	—	$	—	$	—
Renewable energy and RECs^(b)		1,517		75		76		77		78		84		1,127
PECO
Electric supply procurement^(c)		609		527		82		—		—		—		—
AECs^(d)		13		2		2		2		2		2		3
BGE
Electric supply procurement^(e)		1,315		779		448		88		—		—		—
Curtailment services^(f)		115		40		34		29		12		—		—

(a)	ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of December 31, 2014, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017.

(b)

Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms.

(c)

PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2016. 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)	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3—Regulatory Matters for additional information.

(e)	BGE entered into various contracts for the procurement of electricity beginning 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3—Regulatory Matters for additional information.

(f)	BGE has entered into various contracts with curtailment services providers related to transactions in PJM’s capacity market. 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. Beginning with the second quarter of 2014, 100% of CENG’s nuclear fuel commitments are disclosed within the Generation line below, since CENG is now fully consolidated by Generation. PECO and BGE have commitments to purchase natural gas related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of December 31, 2014, these commitments were as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
Generation	$	8,981	$	1,404	$	1,119	$	1,124	$	1,001	$	888	$	3,445
PECO		428		146		103		60		34		14		71
BGE		611		111		82		67		57		54		240

425

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, 2014, which primarily represent commitments for services, materials and information technology, are as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
Exelon	$	894	$	336	$	258	$	150	$	36	$	30	$	84
Generation ^(a)(b)		396		163		67		42		30		24		70
ComEd^(c)		148		63		77		1		1		1		5
PECO^(c)		7		3		4		—		—		—		—
BGE^(c)		343		107		110		107		5		5		9

(a)	Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information.

(b)	Purchase obligations include commitments related to assets-held-for-sale. See Note 4—Mergers, Acquisitions, and Dispositions for additional information.

(c)	Purchase obligations include commitments related to smart meter installation. See Note 3—Regulatory Matters for additional information.

426

Combined Notes to Consolidated Financial Statements—(Continued)

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

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
Letters of credit (non-debt)^(a)	$	1,233	$	1,151	$	77	$	5	$	—	$	—	$	—
Surety bonds^(b)		596		545		10		4		1		2		34
Performance guarantees^(c)		1,239		472		20		20		20		20		687
Energy marketing contract guarantees^(d)		3,220		3,220		—		—		—		—		—
Lease guarantees^(e)		40		—		—		—		—		—		40
Nuclear insurance premiums^(f)		3,014		—		—		—		—		—		3,014
Underwriters discount^(g)		60		60		—		—		—		—		—

Total commercial commitments	$	9,402	$	5,448	$	107	$	29	$	21	$	22	$	3,775

(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. Additionally includes $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 $3.2 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 $0.6 billion at December 31, 2014, which represents the total amount Exelon could be required to fund based on December 31, 2014 market prices.

(e)	Lease guarantees—Guarantees issued to ensure payments on building leases.

(f)

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.

(g)	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 19—Common Stock for further details of the equity securities offering.

427

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, 2014, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
Letters of credit (non-debt)^(a)	$	1,187	$	1,106	$	76	$	5	$	—	$	—	$	—
Surety bonds		481		468		3		—		—		—		10
Performance guarantees^(b)		458		319		20		20		20		20		59
Energy marketing contract guarantees^(c)		1,244		1,244		—		—		—		—		—
Nuclear insurance premiums^(d)		3,014		—		—		—		—		—		3,014

Total commercial commitments	$	6,384	$	3,137	$	99	$	25	$	20	$	20	$	3,083

(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.

(c)

Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.2 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 $0.4 billion at December 31, 2014, which represents the total amount Generation could be required to fund based on December 31, 2014 market prices.

(d)

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, including CENG sites, 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.

ComEd’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
Letters of credit (non-debt)^(a)	$	17	$	17	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)		5		3		—		—		—		—		2
Performance guarantees^(c)		200		—		—		—		—		—		200

Total commercial commitments	$	222	$	20	$	—	$	—	$	—	$	—	$	202

(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)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.

428

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, 2014, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
Letters of credit (non-debt)^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)		18		18		—		—		—		—		—
Performance guarantees^(c)		178		—		—		—		—		—		178

Total commercial commitments	$	218	$	40	$	—	$	—	$	—	$	—	$	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)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

BGE’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2015		2016		2017		2018		2019		2020 and beyond
Letters of credit (non-debt)^(a)	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)		11		11		—		—		—		—		—
Performance guarantees^(c)		253		3		—		—		—		—		250

Total commercial commitments	$	265	$	15	$	—	$	—	$	—	$	—	$	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)	Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE.

Construction Commitments

Generation’s ongoing investments in renewables development and new natural gas construction illustrates Generation’s growth strategy to provide for diversification opportunities while leveraging its expertise and strengths.

Generation completed the construction of the Antelope Valley solar PV facility in Los Angeles County, California, which became fully operational in the first half of 2014. Generation has no further remaining construction commitments for the project.

On July 3, 2013, Generation executed a turbine supply agreement to expand its Beebe wind project in Michigan. The remaining commitment is approximately $2 million under the contract and achievement of commercial operations was attained 2014.

429

Combined Notes to Consolidated Financial Statements—(Continued)

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

On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with at least 120MW of new natural gas-fired generation. The remaining commitment is approximately $39 million under the contract and achievement of commercial operation is expected in 2015. This project will satisfy a portion of Exelon’s commitment to Maryland. See Note 4—Mergers, Acquisitions, and Dispositions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger.

On December 27, 2013, Generated executed a turbine supply agreement for construction of the 40MW Fourmile Wind project in western Maryland. The remaining commitment is approximately $2 million under the contract and achievement of commercial operations was attained in 2014. This project will satisfy a portion of Exelon’s 125 MW Tier I land-based renewables commitment made to Maryland. See Note 4—Mergers, Acquisitions, and Dispositions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger.

During the third and fourth quarter of 2014, Generation executed contracts associated with the construction of new combined-cycle gas turbine units in Texas. The remaining commitment is approximately $1.0 billion under these contracts and achievement of commercial operations is expected in 2017.

During the fourth quarter of 2014 Generation executed contracts associated with the construction of the 30 MW Fair Wind project in western Maryland. The remaining commitment is approximately $19 million under these contracts and achievement of commercial operations is expected in 2015. This project will satisfy a portion of Exelon’s 125 MW Tier I land-based renewables commitment made to Maryland. See Note 4—Mergers, Acquisitions, and Dispositions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger.

During the fourth quarter of 2014 Generation executed contracts associated with the construction of the 78 MW Sendero Wind project in southern Texas. The remaining commitment is approximately $56 million under these contracts and achievement of commercial operations is expected in 2015.

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, and BGE’s comprehensive smart grid initiative.

430

Combined Notes to Consolidated Financial Statements—(Continued)

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

Equity Investment Commitments

As part of Generation’s recent investments in technology development, Generation has entered into equity purchase agreements which include commitments to purchase additional equity through incremental payments. The additional equity is provided by the agreements to fund the anticipated needs of the planned operations of the associated companies. The commitment includes approximately $20 million of in-kind services. As of December 31, 2014, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:


	Total
2015	$	98
2016		38
2017		20
2018		11

Total	$	167

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, 2014 were:


	Exelon			Generation ^(b)			ComEd ^(c)		PECO ^(c)		BGE ^(c)(d)
2015	$	99		$	51		$	14	$	3	$	13
2016		102			57			13		3		11
2017		102			63			8		3		10
2018		86			57			4		3		9
2019		70			43			4		2		7
Remaining years		699			628			2		—		27

Total minimum future lease payments	$	1,158	^(a)	$	899	^(a)	$	45	$	14	$	77

(a)	Excludes Generation’s PPAs and tolling arrangements that are accounted for as contingent operating lease payments, since these expected cash outflows are already disclosed in the Net Capacity Purchases table under the Energy Commitment.

(b)

The Generation column above now includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2014. Generation’s total commitments under the lease agreement are $0 in 2015, and $5 million, $12 million, $13 million, $13 million, and $285 million related to years 2016, 2017, 2018, 2019, and thereafter, respectively, for a total of $328 million .

(c)

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, PECO’s, and BGE’s annual obligation for these arrangements, included in each of the years 2015—2019, was $2 million, $3 million, and $2 million respectively.

(d)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.

431

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2014, 2013 and 2012:


For the Year Ended December 31,	Exelon		Generation ^(a)		ComEd		PECO		BGE
2014	$	865	$	806	$	15	$	14	$	12
2013		806		744		15		21		11
2012		930		872		18		27		12

(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 $755 million, $694 million and $801 million during 2014, 2013 and 2012, respectively.

For information regarding capital lease obligations, see Note 13—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, 2013. The guarantee expired January 31, 2014. Generation was not required to make payments under the guarantee, and, therefore, has no further obligation related to this guarantee.

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 almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

•

ComEd has identified 42 sites, 17 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 25 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 2019.

•

PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites 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 2021.

432

Combined Notes to Consolidated Financial Statements—(Continued)

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

•

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. At this time, BGE is unable to estimate the results of this investigation.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of former MGP facility sites from customers; however, 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. ComEd, PECO and BGE have recorded regulatory assets for the recovery of these costs. See Note 3—Regulatory Matters for additional information regarding the associated regulatory assets.

As of December 31, 2014 and 2013, 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, 2014	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	347	$	277
Generation		63		—
ComEd		238		235
PECO		45		42
BGE		1		—


December 31, 2013	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	338	$	273
Generation		56		—
ComEd		234		229
PECO		47		44
BGE		1		—

The 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 applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

During the third quarter of 2014, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites. Accordingly, ComEd and PECO increased their environmental liabilities and related regulatory assets by $26 million and $4 million, respectively, primarily reflecting refined assumptions regarding clean-up techniques and scopes based on additional experience and analysis as site clean-up and investigation activities progress.

433

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE has established a reserve for the active sites that is not material. Given that the former gas purification site is in the early stages of investigation and the extent of contamination is not currently known, BGE is unable to estimate actual remediation costs, which may be material to BGE’s results of operations, cash flows, and financial position.

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

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. As of December 31, 2014 and 2013, Generation’s remaining groundwater contamination reserve was $13 million and $14 million. respectively.

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.

Under a supplemental agreement reached in 2003, Midwest Generation agreed to reimburse ComEd and Generation for 50% of the specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement.

On December 17, 2012 (Petition Date), EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code.

In 2012, the Bankruptcy Court approved the rejection of an agency agreement related to a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the party responsible for making all remaining payments under the lease and performing all other obligations thereunder. In January 2013, Generation made the final $10 million payment due under the lease agreement which had been accrued at December 31, 2012.

434

Combined Notes to Consolidated Financial Statements—(Continued)

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

On March 11, 2014, the Bankruptcy Court for the Northern District of Illinois entered its Order Confirming Debtors’ Joint Chapter 11 Plan of Reorganization. On April 1, 2014 (Effective Date), NRG Energy purchased EME’s portfolio of generation, including Midwest Generation and the Joint Chapter 11 Plan of Reorganization (Plan) became effective. As part of the Plan, the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement were rejected. Creditors were provided 30 days from the Effective Date to file rejection damages claims associated with contracts rejected under the Plan.

During the second quarter of 2013, Exelon filed proofs of claim for approximately $21 million with the Bankruptcy Court for amounts owed by EME and Midwest Generation related to the coal rail car lease. Further, Exelon filed an environmental claim with an unspecified amount that listed the indemnifications that were in place pre-Petition Date and other factors associated with the remediation and a claim under the asbestos cost-sharing agreement with an unspecified amount. A settlement was approved on January 22, 2015, to resolve the claims related to the coal rail car lease for $14 million. Exelon received the funds and recorded the corresponding gain January 2015.

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 Exelon’s 2001 corporate 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 at the stations requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors. ComEd and Generation have reviewed available public information as to potential environmental exposures regarding the Midwest Generation station sites. Midwest Generation publicly disclosed in its March 31, 2014 Form 10-Q, its last public filing prior to its deregistration, 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 two 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 Crawford, 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 remediation requirements that may be asserted. 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 as a result no liability has been recorded as of December 31, 2014. 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.

Generation increased its reserve for asbestos-related bodily injury claims at December 31, 2013 by $25 million, as a result of Midwest Generation listing such agreement in the January 2014 plan supplement as an agreement to be rejected in connection with the Plan. As discussed above, the rejection became effective as part of the Plan. Subsequently, Generation increased its reserve by $15 million pursuant to the second quarter 2014 actuarial study of such claims, of which an estimated $6 million pertains to Midwest Generation’s share. Midwest Generation publicly disclosed in its March 31, 2014 Form 10-Q, its last public filing prior to its deregistration, that it had $53 million recorded related to asbestos bodily injury claims under the contractual indemnity with ComEd. Exelon and Generation may be entitled to damages associated with the rejection of the agreement. These amounts are considered to be contingent gains and would not be recognized until realized.

435

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. 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 supplemental feasibility study, and subsequently requested additional analysis sampling and modeling that will be conducted throughout 2015. In light of these additional requests, it is unknown when the U.S EPA will propose a remedy for public comment, but will likely be sometime in 2016 at the earliest. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRPs 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. The current estimated cost of the landfill cover remediation for the site is approximately $50 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.

On April 11, 2014, a class action complaint was filed in the U.S. District Court for the Eastern District of Missouri against Cotter and six additional defendants. The complaint alleges that individuals living in the North St. Louis area within a three-mile radius of the West Lake Landfill suffered damage to property or loss of use of property due to the defendants’ negligent handling of radioactive materials. On August 22, 2014, the plaintiffs voluntarily dismissed the case without prejudice.

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 2015 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation 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) and Cotter. The suits allege that individuals living in the North St.

436

Combined Notes to Consolidated Financial Statements—(Continued)

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

Louis area developed some form of cancer due to the Exelon 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 were subsequently granted. Since May 30, 2012, several related lawsuits have been filed in the same court on behalf of various plaintiffs against Cotter and other defendants, but not Exelon. The allegations in these related lawsuits mirror the initially filed lawsuits. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. On March 27, 2013, the U.S. District Court dismissed all state common law actions brought under the initial two lawsuits; and also found that the plaintiffs had not properly brought the actions under the Price-Anderson Act. On July 8, 2013, the plaintiffs filed amended complaints under the Price-Anderson Act. Cotter moved to dismiss the amended complaints and has motions currently pending before the court. At this stage of the litigation, Exelon, Generation, and ComEd 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 PRPs 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. On September 30, 2013, U.S. EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs estimated range of costs noted above. Based on Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual for its share of the estimated clean-up costs. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site.

Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG). In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $10 million, which has been fully reserved as of December 31, 2014.

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, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. 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 March 11, 2013, BGE and three other PRP’s signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which

437

Combined Notes to Consolidated Financial Statements—(Continued)

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

requires the PRP’s to conduct a Remedial Investigation and Feasibility Study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. 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.

Coal Combustion Residuals. On December 19, 2014, the U.S. EPA issued the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants, including the classification of CCR as non-hazardous waste under RCRA. The EPA ruling is effective 180 days after publication in the Federal Register, which is anticipated in early 2015. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation is evaluating what, if any, incremental costs will be incurred for coal ash disposal sites formerly owned by Generation that have not yet been closed by their current owners. At this time, however, Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted for these former sites under the new federal regulations. For these reasons, Generation is unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations, and as a result no new liability has been recorded as of December 31, 2014.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon, Generation, PECO 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, 2014 and 2013, Generation had reserved approximately $100 million and $90 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2014, approximately $22 million of this amount related to 255 open claims presented to Generation, while the remaining $78 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 2014, Generation increased its reserve by approximately $15 million, primarily due to increased actual and projected number and severity of claims.

On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not apply to preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was

438

Combined Notes to Consolidated Financial Statements—(Continued)

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

not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Currently, Exelon, Generation and PECO are unable to predict whether and to what extent they may experience additional claims in the future as a result of this ruling; as such no increase to the asbestos-related bodily injury liability has been recorded as of December 31, 2014. Increased claims activity resulting from this ruling could have a material adverse impact on Exelon, Generation’s and PECO’s future results of operations and cash flows.

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 486 individuals who were never employees of BGE or certain Constellation subsidiaries 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 certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.

Discovery begins in these cases after they are placed on the trial docket. At present, only two of the pending cases are set for trial. Given the limited discovery in these cases, 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 Constellation merger, Constellation announced on March 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay, and has paid, a $135 million civil penalty and $110 million in disgorgement.

During the year ended December 31, 2012, Generation recorded expense of $195 million in Operating and maintenance expense within its Statement of Operations and Comprehensive Income with the remaining $50 million recorded as a Constellation pre-acquisition contingency within its Consolidated Balance Sheets. See Note 4—Mergers, Acquisitions, and Dispositions for additional information on the Constellation merger.

439

Combined Notes to Consolidated Financial Statements—(Continued)

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

Continuous Power Interruption (ComEd)

Section 16-125 of 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). 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 June 5, 2013, the ICC approved a complete waiver of liability for five of the six summer storms and the February 2011 blizzard. The ICC held that for the July 11, 2011 storm, 34,559 interruptions were preventable and therefore no waiver should apply. As required by the ICC’s Order, ComEd notified relevant customers that they may be entitled to seek reimbursement of incurred costs in accordance with a claims procedure established under ICC rules and regulations. In addition, the ICC found that ComEd did not systematically fail in its duty to provide adequate, reliable and safe service. As a result, the ICC rejected the Illinois Attorney General’s request for the ICC to open an investigation into ComEd’s infrastructure and storm hardening investments.

Following the ICC’s June 26, 2013 denial of ComEd’s request for rehearing, on June 27, 2013 ComEd filed an appeal of both the summer and winter storm dockets with the Illinois Appellate Court regarding the ICC’s interpretation of Section 16-125 of the Illinois Public Utilities Act. On July 31, 2014, the Illinois Appellate Court reaffirmed the ICC’s decision in the appeal of the Summer 2011 Storm Docket and dismissed the appeal of the February 2011 Blizzard Docket. The Illinois Appellate Court’s opinion has no accounting impact as ComEd previously established a liability in connection with the June 5, 2013 ICC ruling discussed below. ComEd has asked the Illinois Supreme Court to hear the matter. There is no set time in which the Court must decide whether it will take the case.

As a result of the ICC’s June 5, 2013 ruling, ComEd established a liability, which was not material, for potential reimbursements for actual damages incurred by the 34,559 customers covered by the ICC’s June 5, 2013 Order. The liability recorded represents the low end of a range of potential losses given that no amount within the range represents a better estimate. ComEd’s ultimate liability will be based on actual claims eligible for reimbursement as well as the outcome of the appeal. Although reimbursements for actual damages will differ from the estimated accrual recorded, at this time ComEd does not expect the difference to be material to ComEd’s results of operations or cash flows.

ComEd has not recorded an accrual for reimbursement of local governmental emergency and contingency expenses as a range of loss, if any, cannot be reasonably estimated at this time, but may be material to ComEd’s results of operations and cash flows.

440

Combined Notes to Consolidated Financial Statements—(Continued)

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

Telephone Consumer Protection Act Lawsuit (ComEd)

On November 19, 2013, a class action complaint was filed in the Northern District of Illinois on behalf of a single individual and a presumptive class that would include all customers that ComEd enrolled in its Outage Alert text message program. The complaint alleges that ComEd violated the Telephone Consumer Protection Act (“TCPA”) by sending approximately 1.2 million text messages to customers without first obtaining their consent to receive such messages. The complaint seeks certification of a class along with statutory damages, attorneys’ fees, and an order prohibiting ComEd from sending additional text messages. Such statutory damages could range from $ 500 to $ 1,500 per text. ComEd intends to contest the allegations of this suit. In February 2014, ComEd filed a motion to dismiss this class action complaint, which was denied in June 2014. As of December 31, 2014, ComEd has a reserve, which is not material, representing its best estimate of probable loss associated with this class action complaint. As ComEd is unable to predict the ultimate outcome of this proceeding, actual damages may differ from the estimated amount recorded, which may be material to ComEd’s results of operations, cash flows, and financial position.

Fund Transfer Restrictions (Exelon, Generation, 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. On May 1, 2013, PECO redeemed all outstanding preferred securities. As a result, the above ratio calculation is no longer applicable. 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

441

Combined Notes to Consolidated Financial Statements—(Continued)

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

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.

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.

Baltimore City Franchise Taxes (BGE)

The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE is currently reviewing the merits of this claim. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.

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 14—Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

442

Combined Notes to Consolidated Financial Statements—(Continued)

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

23. 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 and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012.


For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility^(a)	$	456	$	89	$	238	$	128	$	86
Property		396		240		25		15		114
Payroll		200		118		28		14		18
Other		102		18		2		2		3

Total taxes other than income	$	1,154	$	465		293	$	159	$	221


For the year ended December 31, 2013	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility^(a)	$	449	$	79	$	241	$	129	$	82
Property		302		205		24		14		112
Payroll		159		89		27		13		15
Other		185		16		7		2		4

Total taxes other than income	$	1,095	$	389	$	299	$	158	$	213


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

(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 and Comprehensive Income.

443

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the year ended December 31, 2014	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	216		$	216		$	—	$	—		$	—
Non-regulatory agreement units		159			159			—		—			—
Net unrealized gains on decommissioning trust funds—
Regulatory agreement units		180			180			—		—			—
Non-regulatory agreement units		134			134			—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning		29			29			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)		(358	)		(358	)		—		—			—

Total decommissioning-related activities		360			360			—		—			—

Investment income		1			1			—		(1	)		7	^(c)
Long-term lease income		24			—			—		—			—
Interest income related to uncertain income tax positions		40			54			—		—			—
AFUDC—Equity		21			—			3		6			12
Other		9			(9	)		14		2			(1	)

Other, net	$	455		$	406		$	17	$	7		$	18


For the year ended December 31, 2013	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	256		$	256		$	—	$	—		$	—
Non-regulatory agreement units		77			77			—		—			—
Net unrealized gains on decommissioning trust funds—
Regulatory agreement units		406			406			—		—			—
Non-regulatory agreement units		146			146			—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning		7			7			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)		(546	)		(546	)		—		—			—

Total decommissioning-related activities		346			346			—		—			—

Investment income		8			(1	)		—		(1	)		9	^(c)
Long-term lease income		28			—			—		—			—
Interest income related to uncertain income tax positions		24			4			—		—			—
AFUDC—Equity		22			—			11		4			7
Other		32			6			15		3			1

Other, net	$	460		$	355		$	26	$	6		$	17

444

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
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 losses 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		32			1			12		2		2

Other, net	$	353		$	246		$	39	$	8	$	23

(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 15—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.

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012.


For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	2,080	$	922	$	588	$	227	$	288
Regulatory assets		191		—		99		9		83
Amortization of intangible assets, net		44		44		—		—		—
Amortization of energy contract assets and liabilities^(a)		135		135		—		—		—
Nuclear fuel^(b)		1,073		1,073		—		—		—
ARO accretion^(c)		345		345		—		—		—

Total depreciation, amortization, accretion and depletion	$	3,868	$	2,519	$	687	$	236	$	371

445

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the year ended December 31, 2013	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,893	$	813	$	545	$	219	$	264
Regulatory assets		212		—		119		9		84
Amortization of intangible assets, net		48		43		5		—		—
Amortization of energy contract assets and liabilities^(a)		430		507		—		—		—
Nuclear fuel^(b)		921		921		—		—		—
ARO accretion^(c)		275		275		—		—		—

Total depreciation, amortization, accretion and depletion	$	3,779	$	2,559	$	669	$	228	$	348


For the year ended December 31, 2012	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
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^(b)		848		848		—		—		—
ARO accretion^(c)		240		240		—		—		—

Total depreciation, amortization and accretion	$	4,079	$	2,966	$	610	$	217	$	298

(a)	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(b)	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(c)	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

446

Combined Notes to Consolidated Financial Statements—(Continued)

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


For the year ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	940		$	322		$	292		$	94		$	111
Income taxes (net of refunds)	$	314			227			(6	)		85			(21	)

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	560		$	249			162		$	36		$	64
Loss from equity method investments		22			20			—			—			—
Provision for uncollectible accounts		156			14			26			52			64
Provision for excess and obsolete inventory		5			5			—			—			—
Stock-based compensation costs		91			—			—			—			—
Other decommissioning-related activity^(a)		(132	)		(132	)		—			—			—
Energy-related options^(b)		122			122			—			—			—
Amortization of regulatory asset related to debt costs		11			—			8			3			—
Amortization of rate stabilization deferral		65			—			—			—			65
Amortization of debt fair value adjustment		(23	)		(23	)		—			—			—
Merger-related commitments		44			44			—			—			—
Amortization of debt costs		53			12			4			2			2
Discrete impacts from EIMA^(c)		53			—			53			—			—
Lower of cost or market inventory adjustment		29			29			—			—			—
Other		(2	)		6			2			(1	)		(15	)

Total other non-cash operating activities	$	1,054		$	346		$	255		$	92		$	180

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	47		$	—		$	36		$	—		$	11
Other regulatory assets and liabilities		(167	)		—			(13	)		(16	)		(121	)
Cash deposits ^(d)		(241	)		(241	)		—			—			—
Other current assets		7			81			(10	)		(2	)		(44	)
Other noncurrent assets and liabilities		(204	)		(89	)		32			1			(9	)

Total changes in other assets and liabilities	$	(558	)	$	(249	)	$	45		$	(17	)	$	(163	)

Non-cash investing and financing activities:
Change in ARC	$	72		$	72		$	—		$	—		$	—
Change in capital expenditures not paid		220			(61	)^(e)		78			—			25
Fair value of net assets recorded upon CENG consolidation ^(f)		(3,400	)		(3,400	)		—			—			—
Issuance of equity units ^(g)		131			—			—			—			—
Nuclear fuel procurement ^(h)		70			70			—			—			—
Indemnification of like-kind exchange position ⁽ⁱ⁾		—			—			5			—			—

(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 15—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3—Regulatory Matters for more information.

(d)	Relates primarily to cash deposits made to ISO’s/RTO’s.

(e)	Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.

447

Combined Notes to Consolidated Financial Statements—(Continued)

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

(f)	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.

(g)	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 19—Common Stock for additional information.

(h)	Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.

(i)	See Note 14—Income Taxes for discussion of the like-kind exchange tax position.


For the year ended December 31, 2013	Exelon			Generation			ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	866		$	291		$	283		$	95		$	130
Income taxes (net of refunds)		112			(18	)		33			70			42

Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	825		$	345		$	308		$	43		$	56
Gain from equity method investments		(10	)		(10	)		—			—			—
Provision for uncollectible accounts		101			10			(15	)		61			44
Provision for excess and obsolete inventory		9			9			—			—			—
Stock-based compensation costs		120			—			—			—			—
Other decommissioning-related activity ^(a)		(169	)		(169	)		—			—			—
Energy-related options ^(b)		104			104			—			—			—
Amortization of regulatory asset related to debt costs		12			—			9			3			—
Amortization of rate stabilization deferral		66			—			—			—			66
Amortization of debt fair value adjustment		(34	)		(34	)		—			—			—
Discrete impacts from EIMA ^(c)		(271	)		—			(271	)		—			—
Amortization of debt costs		18			10			1			2			2
Other		(53	)		5			(4	)		(1	)		(15	)

Total other non-cash operating activities	$	718		$	270		$	28		$	108		$	153


Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	12		$	—		$	(35	)	$	9		$	38
Other regulatory assets and liabilities		(64	)		—			(43	)		(16	)		(71	)
Other current assets		(165	)		(151	)		51			13			(8	)
Other noncurrent assets and liabilities		322			15			268	^(d)		(12	)		(23	)

Total changes in other assets and liabilities	$	105		$	(136	)	$	241		$	(6	)	$	(64	)


Non-cash investing and financing activities:
Change in ARC	$	(128	)	$	(128	)	$	—		$	—		$	4
Change in capital expenditures not paid		(38	)		(107	)^(e)		(8	)		13			(48	)
Consolidated VIE dividend to noncontrolling interest		63			63			—			—			—
Indemnification of like-kind exchange position ^(f)		—			—			176			—			—

(a)

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3—Regulatory Matters for more information.

(d)	Relates primarily to interest payable related to like-kind exchange tax position. See Note 14—Income Taxes for discussion of the like-kind exchange tax position.

448

Combined Notes to Consolidated Financial Statements—(Continued)

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

(e)	Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.

(f)	See Note 14—Income Taxes for discussion of the like-kind exchanged tax position.


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
Earnings from equity method investments		91			91			—			—			—
Provision for uncollectible accounts		164			22			42			60			44
Provision for excess and 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 ^(c)		141			32			—			—			27
Severance costs		99			34			—			—			—
Discrete impacts from EIMA ^(d)		(96	)		—			(96	)		—			—
Amortization of debt costs		19			11			5			3			2
Other		(30	)		—			5			9			(6	)

Total other non-cash operating activities	$	1,364		$	518		$	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	)		33			(12	)		(7	)
Other noncurrent assets and liabilities		(248	)		(98	)		(95	)		(10	)		8

Total changes in other assets and liabilities	$	(368	)	$	(128	)	$	(102	)	$	16		$	(85	)


Non-cash investing and financing activities:
Change in ARC	$	781		$	781		$	2		$	—		$	—
Change in capital expenditures not paid		160			103	^(e)		15			26			(4	)
Consolidated VIE dividend to noncontrolling interest		7,365			5,264			—			—			—

(a)

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)	Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4—Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments.

(d)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3—Regulatory Matters.

(e)	Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley.

DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2014, PECO has included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $5 million related to PECO’s DOE SGIG programs.

449

Combined Notes to Consolidated Financial Statements—(Continued)

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

For the year ended December 31, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $74 million, $27 million and $47 million, and reimbursements of $95 million, $37 million and $58 million, 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, 2014 and 2013.


December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8
Bloom Energy		13		13		—		—		—
Net Power		9		9		—		—		—
Sunnyside		5		5		—		—		—
Other equity method investments		1		1		—		—		—

Total equity method investments		50		28		6		8		8

Other investments:
Net investment in leases		367		7		—		—		—
Employee benefit trusts and investments^(b)		85		27		—		23		4
Other investments ^(c)		42		42		—		—		—

Total investments	$	544	$	104	$	6	$	31	$	12


December 31, 2013	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8
Keystone Fuels, LLC		32		32		—		—		—
Conemaugh Fuels, LLC		21		21		—		—		—
CENG		1,925		1,925		—		—		—
Safe Harbor		285		285		—		—		—
Malacha		8		8		—		—		—
Other equity method investments		2		2		—		—		—

Total equity method investments		2,295		2,273		6		8		8

Other investments:
Net investment in leases		705		7		—		—		—
Employee benefit trusts and investments^(b)		90		23		5		23		5
Other investments ^(c)		22		22		—		—		—

Total investments	$	3,112	$	2,325	$	11	$	31	$	13

(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments 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.

(c)	Includes cost method and available-for-sale investments.

450

Combined Notes to Consolidated Financial Statements—(Continued)

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

The following tables provide additional information about liabilities of the Registrants at December 31, 2014 and 2013.


December 31, 2014	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)	$	832		$	447		$	153	$	50	$	58
Taxes accrued		305			248			59		3		42
Interest accrued		240			66			102		33		29
Severance accrued		49			33			2		1		2
Other accrued expenses		113	^(b)		92	^(b)		15		4		0

Total accrued expenses	$	1,539		$	886		$	331	$	91	$	131


December 31, 2013	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)	$	683		$	337		$	135	$	47	$	55
Taxes accrued		315			212			62		24		16
Interest accrued		234			72			95		32		29
Severance accrued		66			31			3		1		4
Other accrued expenses		335	^(b)		324	^(b)		12		2		7

Total accrued expenses	$	1,633		$	976		$	307	$	106	$	111

(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

(b)	Includes $19 million and $228 million for amounts accrued related to Antelope Valley as of December 31, 2014 and December 31, 2013, respectively.

24. Segment Information (Exelon, Generation, ComEd, PECO and BGE)

Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.

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. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon’s CODM evaluates the performance of and allocates resources to ComEd, PECO and BGE based on net income and return on equity.

The CODMs for ComEd, PECO, and BGE evaluate performance and allocate resources for their respective companies based on net income and return on equity for ComEd, PECO, and BGE each as single integrated businesses.

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:

•

451

Combined Notes to Consolidated Financial Statements—(Continued)

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

•

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:

•

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

The CODMs for Exelon and Generation evaluate the performance of Generation’s power marketing activities and allocate resources 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 sales to its affiliates, 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 Generation’s own generation and fuel costs associated with tolling agreements. Generation’s other business activities, including retail and wholesale gas, investments in gas and oil exploration and production activities, proprietary trading, distributed generation, 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, and investments in energy-related proprietary technology 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, unrealized mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value are also not allocated to a region. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

452

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, 2014, 2013, and 2012 is as follows:


	Generation ^(a)			ComEd		PECO		BGE ^(b)			Other ^(c)			Intersegment Eliminations			Exelon
Operating revenues^(d):
2014	$	17,393		$	4,564	$	3,094	$	3,165		$	1,285		$	(2,072	)	$	27,429
2013		15,630			4,464		3,100		3,065			1,241			(2,612	)		24,888
2012		14,437			5,443		3,186		2,091			1,396			(3,064	)		23,489
Intersegment revenues^(e):
2014	$	762		$	4	$	2	$	25		$	1,280		$	(2,067	)	$	6
2013		1,367			3		1		13			1,237			(2,607	)		14
2012		1,660			2		3		9			1,381			(3,049	)		6
Depreciation and amortization
2014	$	967		$	687	$	236	$	371		$	53		$	—		$	2,314
2013		856			669		228		348			52			—			2,153
2012		768			610		217		238			48			—			1,881
Operating expenses ^(d):
2014	$	16,923		$	3,586	$	2,522	$	2,726		$	1,353		$	(2,071	)	$	25,039
2013		13,976			3,510		2,434		2,616			1,324			(2,618	)		21,242
2012		13,226			4,557		2,563		2,053			1,662			(3,043	)		21,018
Equity in earnings (losses) of unconsolidated affiliates
2014	$	(20	)	$	—	$	—	$	—		$	—		$	—		$	(20	)
2013		10			—		—		—			—			—			10
2012		(91	)		—		—		—			—			—			(91	)
Interest expense, net:
2014	$	356		$	321	$	113	$	106		$	169		$	—		$	1,065
2013		357			579		115		122			183			—			1,356
2012		301			307		123		111			86			—			928
Income (loss) before income taxes:
2014	$	1,226		$	676	$	466	$	351		$	(227	)	$	(6	)	$	2,486
2013		1,675			401		557		344			(191	)		(13	)		2,773
2012		1,058			618		508		(54	)		(325	)		(7	)		1,798
Income taxes:
2014	$	207		$	268	$	114	$	140		$	(63	)	$	—		$	666
2013		615			152		162		134			(20	)		1			1,044
2012		500			239		127		(23	)		(215	)		(1	)		627
Net income (loss):
2014	$	1,019		$	408	$	352	$	211		$	(164	)	$	(6	)	$	1,820
2013		1,060			249		395		210			(171	)		(14	)		1,729
2012		558			379		381		(31	)		(110	)		(6	)		1,171
Capital expenditures:
2014	$	3,012		$	1,689	$	661	$	620		$	95		$	—		$	6,077
2013		2,752			1,433		537		587			86			—			5,395
2012		3,554			1,246		422		500			67			—			5,789
Total assets:
2014	$	45,348		$	25,392	$	9,943	$	8,078		$	9,794		$	(11,741	)	$	86,814
2013		41,232			24,118		9,617		7,861			8,317			(11,221	)		79,924

453

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. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 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 year ended December 31, 2012, intersegment revenues for Generation 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.

(b)	Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2014.

(c)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.

(d)

For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.

(e)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Generation total revenues:

As of April 1, 2014, Generation total revenues and Generation total revenues net of purchased power and fuel expense includes 100% of the activity from CENG.


	2014							2013							2012
	Revenues from external customers ^(a)		Intersegment revenues			Total Revenues		Revenues from external customers ^(a)		Intersegment revenues			Total Revenues		Revenues from external customers ^(a)		Intersegment revenues			Total Revenues
Mid-Atlantic	$	5,265	$	(6	)	$	5,259	$	5,182	$	22		$	5,204	$	5,082	$	(44	)	$	5,038
Midwest		4,467		8			4,475		4,280		(10	)		4,270		4,824		24			4,848
New England		1,417		5			1,422		1,245		(8	)		1,237		1,048		45			1,093
New York		843		—			843		735		(21	)		714		582		(25	)		557
ERCOT		938		(3	)		935		1,222		(6	)		1,216		1,365		2			1,367
Other Regions ^(b)		1,319		(10	)		1,309		946		22			968		755		78			833

Total Revenues for Reportable Segments	$	14,249	$	(6	)	$	14,243	$	13,610	$	(1	)	$	13,609	$	13,656	$	80		$	13,736

Other ^(c)		3,144		6			3,150		2,020		1			2,021		781		(80	)		701

Total Generation Consolidated Operating Revenues	$	17,393	$	—		$	17,393	$	15,630	$	—		$	15,630	$	14,437	$	—		$	14,437

(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 of $289 million, $767 million, and $1,505 million for the years ended December 31, 2014, 2013, and 2012, respectively, and elimination of intersegment revenues.

454

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:


	2014									2013								2012
	RNF from external customers ^(a)			Intersegment RNF			Total RNF			RNF from external customers ^(a)		Intersegment RNF			Total RNF			RNF from external customers ^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	3,466		$	(49	)	$	3,417		$	3,273	$	(3	)	$	3,270		$	3,477	$	(44	)	$	3,433
Midwest		2,580			14			2,594			2,585		1			2,586			2,974		24			2,998
New England		432			(81	)		351			217		(32	)		185			151		45			196
New York		457			26			483			14		(18	)		(4	)		101		(25	)		76
ERCOT		573			(256	)		317			604		(168	)		436			403		2			405
Other Regions ^(b)		611			(284	)		327			334		(133	)		201			53		78			131

Total Revenues net of purchased power and fuel expense for Reportable Segments	$	8,119		$	(630	)	$	7,489		$	7,027	$	(353	)	$	6,674		$	7,159	$	80		$	7,239

Other ^(c)		(651	)		630			(21	)		406		353			759			217		(80	)		137

Total Generation Revenues net of purchased power and fuel expense	$	7,468		$	—		$	7,468		$	7,433	$	—		$	7,433		$	7,376	$	—		$	7,376

(a)	Includes purchases and sales from 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 of $124 million, $488 million, and $1,098 million, for the years ended December 31, 2014, 2013, and 2012, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

455

Combined Notes to Consolidated Financial Statements—(Continued)

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

25. 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,
	2014			2013		2012
Operating revenues from affiliates:
PECO ^(a)	$	1		$	10	$	6
CENG ^(b)		17			56		42
BGE ^(a)		5			4		—

Total operating revenues from affiliates	$	23		$	70	$	48

Purchase power and fuel from affiliates:
CENG^(c)	$	282		$	992	$	793
Keystone Fuels, LLC ^(d)		138			144		119
Conemaugh Fuels, LLC ^(d)		99			98		101
Safe Harbor Water Power Corp ^(d)		12			22		23

Total purchase power and fuel from affiliates	$	531		$	1,256	$	1,036

Interest expense to affiliates, net:
ComEd Financing III	$	13		$	13	$	13
PECO Trust III		6			6		6
PECO Trust IV		6			6		6
BGE Capital Trust II ^(f)		16			16		12

Total interest expense to affiliates, net	$	41		$	41	$	37

Earnings (losses) in equity method investments:
CENG ^(e)	$	(19	)	$	9	$	(99	)
Qualifying facilities and domestic power projects		(1	)		1		8

Total earnings (losses) in equity method investments	$	(20	)	$	10	$	(91	)


	December 31,
	2014		2013
Receivables from affiliates (current):
CENG ^(b)	$	—	$	3
Payables to affiliates (current):
CENG ^(c)	$	—	$	85
ComEd Financing III		4		4
PECO Trust III		1		1
BGE Capital Trust II		3		4
Keystone Fuels, LLC ^(d)		—		12
Conemaugh Fuels, LLC ^(d)		—		9
Other		—		1

Total payables to affiliates (current)	$	8	$	116

Long-term debt due to financing trusts:
ComEd Financing III	$	206	$	206
PECO Trust III		81		81
PECO Trust IV		103		103
BGE Capital Trust II		258		258

Total long-term debt due to financing trusts	$	648	$	648

456

Combined Notes to Consolidated Financial Statements—(Continued)

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

(a)

The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.

(b)

Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.

(c)

CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing 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 nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.

(d)

During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.

(e)

Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.

(f)	The BGE Capital Trust II portion of Exelon’s interest expense to affiliates, net, for December 31, 2012 excludes $4 million of expense incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012.

457

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,
	2014			2013		2012
Operating revenues from affiliates:
ComEd ^(a)	$	176		$	506	$	795
PECO ^(b)		198			405		543
BGE ^(c)		387			455		322
CENG ^(d)		17			56		42
BSC		1			1		—

Total operating revenues from affiliates	$	779		$	1,423	$	1,702

Purchase power and fuel from affiliates:
ComEd	$	1		$	1	$	—
BGE		25			13		8
CENG ^(e)		282			992		793
Keystone Fuels, LLC ⁽ⁱ⁾		138			144		119
Conemaugh Fuels, LLC ⁽ⁱ⁾		99			98		101
Safe Harbor Water Power Corporation⁽ⁱ⁾		12			22		23

Total purchase power and fuel from affiliates	$	557		$	1,270	$	1,044

Operating and maintenance from affiliates:
ComEd^(f)	$	3		$	2	$	2
PECO^(f)		2			1		3
BSC^(g)		618			571		625

Total operating and maintenance from affiliates	$	623		$	574	$	630

Interest expense to affiliates, net:
Exelon Corporate	$	53		$	59	$	75
Earnings (losses) in equity method investments
CENG^(h)	$	(19	)	$	9	$	(99	)
Qualifying facilities and domestic power projects		(1	)		1		8

Total earnings (losses) in equity method investments	$	(20	)	$	10	$	(91	)

Capitalized costs
BSC	$	91		$	93	$	80
Cash distribution paid to member	$	645		$	625	$	1,626
Contribution from member	$	53		$	26	$	48

458

Combined Notes to Consolidated Financial Statements—(Continued)

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


	December 31,
	2014		2013
Receivables from affiliates (current):
CENG ^(d)	$	—	$	3
ComEd ^(a)		43		38
PECO ^(b)		29		38
BGE ^(c)		40		27
Other		1		2

Total receivables from affiliates (current)	$	113	$	108

Long-term debt due to affiliates (current):
Exelon Corporate ^(l)		556		—
Payables to affiliates (current):
CENG ^(e)	$	—	$	85
Exelon Corporate ^(j)		12		7
BSC ^(g)		83		66
ComEd		12		—
Keystone Fuels, LLC ⁽ⁱ⁾		—		12
Conemaugh Fuels, LLC ⁽ⁱ⁾		—		9
Other		—		2

Total payables to affiliates (current)	$	107	$	181

Long-term debt due to affiliates (noncurrent):
Exelon Corporate ^(l)		943		1,523
Payables to affiliates (noncurrent):
BSC ^(g)	$	1	$	—
ComEd ^(k)		2,389		2,293
PECO ^(k)		490		447

Total payables to affiliates (noncurrent)	$	2,880	$	2,740

(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 provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. 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.

459

Combined Notes to Consolidated Financial Statements—(Continued)

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

(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.

(h)

Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.

(i)

(j)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.

(k)

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations.

(l)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, 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.

460

Combined Notes to Consolidated Financial Statements—(Continued)

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

ComEd

The financial statements of ComEd include related party transactions as presented in the tables below:


	For the Years Ended December 31,
	2014		2013		2012
Operating revenues from affiliates
Generation	$	4	$	3	$	2
Purchased power from affiliate
Generation^(a)	$	176	$	512	$	789
Operating and maintenance from affiliate
BSC^(b)	$	166	$	157	$	163
Interest expense to affiliates, net:
ComEd Financing III	$	13	$	13	$	13
Capitalized costs
BSC^(b)	$	77	$	69	$	92
Cash dividends paid to parent	$	307	$	220	$	105
Contribution from parent	$	273	$	—	$	11


	December 31,
	2014		2013
Prepaid voluntary employee beneficiary association trust^(c)	$	13	$	13
Receivable from affiliates (current):
Voluntary employee beneficiary association trust	$	2	$	3
Generation		12		—

Total receivable from affiliates (current)	$	14	$	3

Receivable from affiliates (noncurrent):
Generation^(d)	$	2,389	$	2,293
Exelon Corporate^(e)		182		176

Total receivable from affiliates (noncurrent)	$	2,571	$	2,469

Payables to affiliates (current):
Generation ^(a)	$	43	$	38
BSC ^(b)		32		30
ComEd Financing III		4		4
PECO		2		—
Exelon Corporate		3		9
Other		—		2

Total payables to affiliates (current)	$	84	$	83

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, which expired in 2013. See Note 3—Regulatory Matters and Note 12—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.

461

Combined Notes to Consolidated Financial Statements—(Continued)

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

(c)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. 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)	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.

PECO

The financial statements of PECO include related party transactions as presented in the tables below:


	For the Years Ended December 31,
	2014		2013		2012
Operating revenues from affiliates:
Generation ^(a)	$	2	$	1	$	3
Purchased power from affiliate
Generation^(b)	$	194	$	392	$	533
Operating and maintenance from affiliates:
BSC ^(c)	$	96	$	98	$	107
Generation		3		3		4

Total operating and maintenance from affiliates	$	99	$	101	$	111

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)	$	39	$	46	$	54
Cash dividends paid to parent	$	320	$	332	$	343
Contribution from parent	$	24	$	27	$	9

462

Combined Notes to Consolidated Financial Statements—(Continued)

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


	December 31,
	2014		2013
Prepaid voluntary employee beneficiary association trust^(d)	$	3	$	3
Receivable from affiliate (current):
ComEd	$	2	$	—
BGE		1		3

Total receivable from affiliates (current)	$	3	$	3

Receivable from affiliate (noncurrent):
Generation ^(e)	$	490	$	447
Payables to affiliates (current):
Generation^(b)	$	29	$	38
BSC^(c)		20		17
Exelon Corporate		2		2
PECO Trust III		1		1

Total payables to affiliates (current)	$	52	$	58

Long-term debt to financing trusts:
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.

(b)

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 Registrants. 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.

463

Combined Notes to Consolidated Financial Statements—(Continued)

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

BGE

The financial statements of BGE include related party transactions as presented in the tables below:


	For the Years Ended December 31,
	2014		2013		2012
Operating revenues from affiliates:
Generation^(a)	$	25	$	13	$	10
Purchased power from affiliate
Generation^(b)	$	382	$	452	$	396
Operating and maintenance from affiliates:
BSC^(c)	$	103	$	83	$	106
Interest expense to affiliates, net:
BGE Capital Trust II	$	16	$	16	$	16
Capitalized costs
BSC^(c)	$	19	$	15	$	21
Contribution from parent	$	—	$	—	$	66


	December 31,
	2014		2013
Prepaid voluntary employee beneficiary association trust^(d)	$	1	$	1
Payables to affiliates (current):
Generation ^(b)	$	40	$	27
BSC ^(c)		17		20
Exelon Corporate		5		1
PECO		1		3
BGE Capital Trust II		3		4

Total payables to affiliates (current)	$	66	$	55

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.

(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)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’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.

464

Combined Notes to Consolidated Financial Statements—(Continued)

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

26. Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE)

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 (Loss) Income on Common Stock
	2014		2013		2014			2013			2014			2013
Quarter ended:
March 31	$	7,237	$	6,082	$	168	^(a)	$	513	^(b)	$	90		$	(4	)^(c)
June 30		6,024		6,141		842	^(a)		1,005			522			490
September 30		6,912		6,502		1,739	^(a)		1,262	^(b)		993			738
December 31		7,255		6,163		348			889			18	^(d)		495

(a)

In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon’s Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon’s Net (Loss) Income on Common Stock.

(b)

In the first and third quarter of 2013, Exelon reclassified $5 million and $8 million, respectively, to Operating income for presentation purposes in Exelon’s Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon’s Net (Loss) Income on Common Stock.

(c)	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

(d)	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.


	Average Basic Shares Outstanding (in millions)				Net (Loss) Income per Basic Share
	2014		2013		2014		2013
Quarter ended:
March 31		858		855	$	0.10	$	(0.01	)
June 30		860		856		0.61		0.57
September 30		861		857		1.15		0.86
December 31		861		856		0.02		0.60

	Average Diluted Shares Outstanding (in millions)				Net (Loss) Income per Diluted Share
	2014		2013		2014		2013
Quarter ended:
March 31		861		855	$	0.10	$	(0.01	)
June 30		864		860		0.60		0.57
September 30		863		860		1.15		0.86
December 31		868		860		0.02		0.59

465

Combined Notes to Consolidated Financial Statements—(Continued)

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

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


	2014								2013
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	38.93	$	36.26	$	37.73	$	33.94	$	30.59	$	32.42	$	37.80	$	34.56
Low price		33.07		30.66		33.11		26.45		26.64		29.42		29.84		29.10
Close		37.08		34.09		36.48		33.56		27.39		29.64		30.88		34.48
Dividends		0.310		0.310		0.310		0.310		0.310		0.310		0.310		0.525

Generation

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:


	Operating Revenues				Operating (Loss) Income						Net (Loss) Income on Membership Interest
	2014		2013		2014^(a)			2013			2014			2013
Quarter ended:
March 31	$	4,390	$	3,533	$	(384	)^(a)	$	(59	)^(b)	$	(185	)	$	(18	)
June 30		3,789		4,070		441	^(a)		603			340			330
September 30		4,412		4,255		1,225	^(a)		729	^(b)		771			490
December 31		4,802		3,772		(105	)		405			(91	)		269

(a)

In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation’s Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation’s Net (Loss) Income on Membership Interest.

(b)

In the first and third quarter of 2013, Generation reclassified $5 million and $8 million, respectively, to Operating (loss) income for presentation purposes in Generation’s Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation’s Net (Loss) Income on Membership Interest.

ComEd

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:


	Operating Revenues				Operating Income					Net (Loss) Income
	2014		2013		2014			2013		2014		2013
Quarter ended:
March 31	$	1,134	$	1,160	$	238		$	209	$	98	$	(81	)
June 30		1,128		1,080		259	^(a)		232		111		96
September 30		1,222		1,156		288	^(a)		278		126		126
December 31		1,079		1,068		196			236		73		109

(a)	In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd’s Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd’s Net (Loss) Income.

466

Combined Notes to Consolidated Financial Statements—(Continued)

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

PECO

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:


	Operating Revenues				Operating Income				Net Income on Common Stock
	2014		2013		2014		2013		2014		2013
Quarter ended:
March 31	$	993	$	895	$	149	$	203	$	89	$	121
June 30		656		672		134		138		84		72
September 30		693		728		133		155		81		92
December 31		750		805		156		168		98		102

BGE

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:


	Operating Revenues				Operating Income				Net Income attributable to Common Shareholders
	2014		2013		2014		2013		2014		2013
Quarter ended:
March 31	$	1,054	$	880	$	169	$	163	$	85	$	77
June 30		653		653		55		69		16		22
September 30		697		737		102		114		46		50
December 31		761		794		113		101		52		47

467

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 2014, 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.

Consistent with guidance issued by the Securities and Exchange Commission that an assessment of internal controls over financial reporting of a recently acquired business may be omitted from management’s evaluation of disclosure controls and procedures, management is excluding an assessment of such internal controls of Integrys, which we acquired on November 1, 2014, from its evaluation of the effectiveness of Exelon’s and Generation’s disclosure controls and procedures. The total assets related to Integrys are approximately 0.74% and 1.42%, respectively, and total revenues related to Integrys are 1.41% and 2.22%, respectively, of Exelon’s and Generation’s related consolidated financial statement amounts as of and for the year ended December 31, 2014.

Accordingly, as of December 31, 2014, 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 2014 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, 2014. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2014 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.

468

ITEM 9B.

OTHER INFORMATION

Exelon, Generation and ComEd

None.

PECO and BGE

None.

469

PART III

Exelon Generation Company, LLC, Baltimore Gas and Electric Company, and PECO Energy 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, BGE, and PECO 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 13, 2015.

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 2015 proxy statement (2015 Exelon Proxy Statement) and the ComEd information statement (2015 ComEd Information Statement) to be filed with the SEC before April 30, 2015 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 and ComEd’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website 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.

470

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 2015 Exelon Proxy Statement or the ComEd 2015 Information Statement and incorporated herein by reference.

471

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 2015 Exelon Proxy Statement or the ComEd 2015 Information Statement 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, warrants and
rights (Note 1)

Weighted-average
price of outstanding
Options, warrants
and rights (Note 2)

Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in
column [B]) (Note 3)

Equity compensation plans approved by security holders

31,538,000

36.67

32,278,000

(1)

Balance includes stock options, unvested performance shares, and 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. For performance shares and performance share transition awards granted in 2013 and 2014, the total includes the maximum number of shares that could be granted, if performance, total shareholder return modifier, and individual performance multipliers were all at maximum, a total of 7,138,000 shares. At target, the number of securities to be issued for such awards is 3,753,000. The deferred stock units granted to directors includes 284,000 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon board of directors, and 98,000 shares to be issued upon the conversion of stock units held by members of the Exelon board of directors that were earned under a legacy Constellation Energy Group plan. Conversion of stock units to shares will occur after the director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 19—Common Stock of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.

(2)	Includes outstanding restricted stock units and performance shares that can be exercised for no consideration. Without such instruments, the weighted-average price of outstanding options, warrants and rights shown in column [C] would be $46.81.

(3)	Includes 23,460,000 shares available for issuance from the company’s employee stock purchase plan.

No ComEd securities are authorized for issuance under equity compensation plans.

472

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 2015 Exelon Proxy Statement or the ComEd 2015 Information Statement and incorporated herein by reference.

473

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 2015 in the 2015 Proxy Statement and the 2015 ComEd Information Statement and incorporated herein by reference.

474

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 13, 2015 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Balance Sheets at December 31, 2014 and 2013

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2014 and 2013 and for the Years Ended December 31, 2014, 2013 and 2012

		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.

475

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)	2014			2013			2012
Operating expenses
Operating and maintenance	$	9		$	9		$	201
Operating and maintenance from affiliates		38			34			72
Other		3			12			6

Total operating expenses		50			55			279
Operating loss		(50	)		(55	)		(279	)

Other income and (deductions)
Interest expense, net		(237	)		(116	)		(153	)
Equity in earnings of investments		1,779			1,903			1,278
Interest income from affiliates, net		53			36			75
Other, net		(2	)		(78	)		7

Total other income		1,593			1,745			1,207

Income before income taxes		1,543			1,690			928
Income taxes (benefit)		(80	)		(29	)		(232	)

Net income	$	1,623		$	1,719		$	1,160

Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service cost (benefit) reclassified to periodic costs	$	(30	)	$	—		$	1
Actuarial loss reclassified to periodic cost		147			208			168
Transition obligation reclassified to periodic cost		—			—			2
Pension and non-pension postretirement benefit plan valuation adjustment		(497	)		669			(371	)
Unrealized loss on cash flow hedges		(148	)		(248	)		(120	)
Unrealized gain on marketable securities		1			2			2
Unrealized gain on equity investments		8			106			1
Unrealized loss on foreign currency translation		(9	)		(10	)		—
Reversal of CENG equity method AOCI		(116	)		—			—

Other comprehensive income (loss)		(644	)		727			(317	)

Comprehensive income	$	979		$	2,446		$	843

See Notes to Financial Statements

476

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)	2014			2013			2012
Net cash flows provided by operating activities	$	806		$	1,053		$	2,131

Cash flows from investing activities
Return on investment of direct financing lease termination		335			—			—
Changes in Exelon intercompany money pool		(83	)		(60	)		—
Note receivable from affiliates		—			484			—
Capital expenditures		1			—			(30	)
Cash and restricted cash acquired from Constellation		—			—			679
Change in restricted cash		—			38			(38	)
Investment in affiliates		(70	)		(38	)		(67	)
Other investing activities		(126	)		15			—

Net cash flows provided by (used in) investing activities		57			439			544

Cash flows from financing activities
Cash receipts from intercompany money pool		—			—			(703	)
Changes in short-term borrowings		—			10			(161	)
Issuance of long-term debt		1,150			—			—
Retirement of long-term debt		(23	)		(450	)		(77	)
Dividends paid on common stock		(1,065	)		(1,249	)		(1,716	)
Proceeds from employee stock plans		35			47			73
Other financing activities		(84	)		(6	)		30

Net cash flows provided by (used in) financing activities		13			(1,648	)		(2,554	)

Increase (decrease) in cash and cash equivalents		876			(156	)		121
Cash and cash equivalents at beginning of period		3			159			38

Cash and cash equivalents at end of period	$	879		$	3		$	159

See Notes to Financial Statements

477

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets


	December 31,
(In millions)	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	879	$	3
Accounts receivable, net
Other accounts receivable		209		72
Accounts receivable from affiliates		24		22
Deferred income taxes		20		27
Notes receivable from affiliates		818		179
Regulatory assets		254		233
Other		22		1

Total current assets		2,226		537

Property, plant and equipment, net		54		57
Deferred debits and other assets
Regulatory assets		3,186		3,005
Investments in affiliates		26,670		26,390
Deferred income taxes		2,187		1,890
Notes receivable from affiliates		943		1,522
Other		172		17

Total deferred debits and other assets		33,158		32,824

Total assets	$	35,438	$	33,418

See Notes to Financial Statements

478

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets


	December 31,
(In millions)	2014			2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	1,409		$	10
Accounts payable		2			43
Unamortized energy contract liabilities		—			12
Accrued expenses		25			106
Deferred income taxes		60			26
Regulatory liabilities		51			2
Other		75			54

Total current liabilities		1,622			253

Long-term debt		2,841			3,033
Long-term debt to affiliate		182			176
Deferred credits and other liabilities
Regulatory liabilities		37			43
Pension obligations		7,638			6,444
Non-pension postretirement benefit obligations		16			393
Deferred income taxes		93			70
Other		398			271

Total deferred credits and other liabilities		8,182			7,221

Total liabilities		12,827			10,683

Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 860 and 857 shares outstanding at December 31, 2014 and 2013, respectively)		16,709			16,741
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013, respectively)		(2,327	)		(2,327	)
Retained earnings		10,910			10,358
Accumulated other comprehensive loss, net		(2,684	)		(2,040	)

Total shareholders’ equity		22,608			22,732

BGE preference stock not subject to mandatory redemption		3			3

Total liabilities and shareholders’ equity	$	35,438		$	33,418

See Notes to Financial Statements

479

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%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. Exelon owned none of PECO’s preference securities, which PECO redeemed in 2013.

2. Mergers

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—Mergers, Acquisitions, and Dispositions 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.

480

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

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 both December 31, 2014 and December 31, 2013.

Credit Agreements

On May 30, 2014, Exelon Corporate amended and extended its unsecured syndicated revolving credit facility with aggregate bank commitments of $500 million through May 2019. As of December 31, 2014, Exelon Corporation had available capacity under those commitments of $494 million. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon Corporation’s credit agreement.

Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2014 and December 31, 2013:


			Maturity Date		December 31,
	Rates		Maturity Date		2014			2013
Long-term debt
Junior subordinated notes		6.5%		2017	$	1,150		$	—
Senior unsecured notes ^(a)		4.9% – 7.6%		2015-2035		2,658			2,658

Total long-term debt						3,808			2,658
Unamortized debt discount and premium, net						1			2
Fair value adjustment						441			383
Long-term debt due within one year						(1,409	)		(10	)

Long-term debt					$	2,841		$	3,033

(a)	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation’s balance sheets.

The debt maturities for Exelon Corporate for the periods 2015, 2016, 2017, 2018, 2019 and thereafter are as follows:


2015	$	1,350
2016		—
2017		1,150
2018		—
2019		—
Remaining years		1,308

Total long-term debt	$	3,808

481

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

4. Commitments and Contingencies

See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.

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,
(In millions)	2014			2013			2012
Operating and maintenance from affiliates:
Business Services Company, LLC^(a)	$	38		$	34		$	72
Interest income from affiliates, net:
Exelon Generation Consolidated	$	53		$	36		$	75
Equity in earnings of investments:
Exelon Energy Delivery Company, LLC ^(b)	$	958		$	834		$	713
Exelon Ventures Company, LLC ^(c)		926			1,076			564
UII, LLC		(6	)		(2	)		25
Exelon Transmission Company, LLC		(7	)		(5	)		(3	)
Exelon Enterprise		(1	)		—			—
Exelon Generation Consolidated		(91	)		—			—
Exelon Consolidations^(d)		—			—			(21	)

Total equity in earnings of investments	$	1,779		$	1,903		$	1,278

Cash contributions received from affiliates	$	1,370		$	1,175		$	2,074

482

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements


	December 31,
(in millions)	2014		2013
Accounts receivable from affiliates (current):
Business Services Company, LLC ^(a)	$	2	$	3
Generation		12		7
ComEd		3		9
PECO		2		2
BGE		5		1

Total accounts receivable from affiliates (current)	$	24	$	22

Notes receivable from affiliates (current):
Business Services Company, LLC^(a)	$	262	$	179
Exelon Generation Consolidated ^(e)	$	556	$	—

Total receivable from affiliates (current):	$	818	$	179

Investments in affiliates:
Business Services Company, LLC^(a)	$	193	$	201
Exelon Energy Delivery Company, LLC^(b)		13,590		12,956
Exelon Ventures Company, LLC^(c)		—		12,750
UII, LLC		130		470
Exelon Transmission Company, LLC		1		3
VEBA		9		10
Exelon Enterprises		23		—
Exelon Generation Consolidated		12,720		—
Exelon Consolidations		4		—

Total investments in affiliates	$	26,670	$	26,390

Notes receivable from affiliates (non-current):
Generation ^(e)	$	943	$	1,522
Long-term debt to affiliates (non-current):
ComEd	$	182	$	176

(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 consisted of Generation and was fully dissolved as of December 31, 2014. Exelon Enterprises, Exelon Generation Consolidated, and Exelon Consolidations are now directly owned Exelon Corporate investments as of December 31, 2014.

(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)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, 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.

483

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, 2014

Allowance for uncollectible accounts ^(a)	$	272	$	175	$	69	^(c)	$	205	^(d)	$	311

Deferred tax valuation allowance		13		—		37			—			50

Reserve for obsolete materials		58		5		34			2			95

For the year ended December 31, 2013

Allowance for uncollectible accounts ^(a)	$	293	$	121	$	37	^(c)	$	179	^(d)	$	272

Deferred tax valuation allowance		36		1		—			24			13

Reserve for obsolete materials		53		17		—			12			58

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

(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, and $8 million for the years ended December 31, 2014, 2013, and 2012, 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.

484

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 13, 2015 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Balance Sheets at December 31, 2014 and 2013

		Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 2014, 2013 and 2012

		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

485

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, 2014

Allowance for uncollectible accounts	$	57	$	14		$	8		$	19		$	60

Deferred tax valuation allowance		11		—			37			—			48

Reserve for obsolete materials		55		5			32			(1	)		93

For the year ended December 31, 2013

Allowance for uncollectible accounts	$	84	$	(16	)	$	—		$	11		$	57

Deferred tax valuation allowance		35		1			—			25			11

Reserve for obsolete materials		50		16			—			11			55

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

(a)	Represents the addition of Constellation’s results as of March 12, 2012, the date of the merger.

486

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 13, 2015 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Balance Sheets at December 31, 2014 and 2013

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012

		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

487

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, 2014

Allowance for uncollectible accounts	$	62	$	45	$	33	^(a)	$	56	^(b)	$	84

Reserve for obsolete materials		2		—		2			2			2

For the year ended December 31, 2013

Allowance for uncollectible accounts	$	70	$	33	$	29	^(a)	$	70	^(b)	$	62

Reserve for obsolete materials		2		1		—			1			2

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

(a)	Primarily charges for late payments and non-service receivables.

(b)	Write-off of individual accounts receivable.

488

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 13, 2015 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Balance Sheets at December 31, 2014 and 2013

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012

		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

489

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, 2014

Allowance for uncollectible accounts^(a)	$	107	$	52	$	11	^(b)	$	70	^(c)	$	100

Reserve for obsolete materials		1		—		—			—			1

For the year ended December 31, 2013

Allowance for uncollectible accounts^(a)	$	99	$	61	$	7	^(b)	$	60	^(c)	$	107

Reserve for obsolete materials		1		—		—			—			1

For the year ended December 31, 2012

Allowance for uncollectible accounts^(a)	$	92	$	60	$	8	^(b)	$	61	^(c)	$	99

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, and $8 million for the years ended December 31, 2014, 2013, and 2012, respectively.

(b)	Primarily charges for late payments.

(c)	Write-off of individual accounts receivable.

490

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 13, 2015 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

		Consolidated Balance Sheets at December 31, 2014 and 2013

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012

		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

491

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, 2014

Allowance for uncollectible accounts	$	46	$	64	$	17	^(b)	$	60	^(a)	$	67

Deferred tax valuation allowance		1		—		—			—			1

Reserve for obsolete materials		1		—		—			1			—

For the year ended December 31, 2013

Allowance for uncollectible accounts	$	40	$	43	$	1		$	38	^(a)	$	46

Deferred tax valuation allowance		1		—		—			—			1

Reserve for obsolete materials		1		—		—			—			1

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

(a)	Write-off of individual accounts receivable.

(b)	Primarily charges for late payments.

492

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		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).

2-2		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).

2-3		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).

2-4		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).

2-5		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 2-1).

2-6		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 Energy Group, Inc., File No. 1-12869).

2-7		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 Energy Group, Inc., File No. 1-12869).

2-8		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 Energy Group, Inc., File Nos. 1-12869 and 1-1910).

2-9		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 Energy Group, Inc., File Nos. 1-12869 and 1-1910).

2-10-1		Agreement and Plan of Merger, dated as of April 29, 2014, by and among Exelon Corporation, Pepco Holdings, Inc. and Purple Acquisition Corp. (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit 2.1).

493


Exhibit No.		Description

2-10-2		Amended and Restated Agreement and Plan of Merger, dated as of July 18, 2014, among Pepco Holdings, Inc., Exelon Corporation and Purple Acquisition Corp. (File No. 001-16169, Form 8-K dated July 21, 2014, Exhibit 2.1).

2-10-3		Subscription Agreement for Series A Non-Voting Non-Convertible Preferred Stock, dated as of April 29, 2014, by and between Pepco Holdings, Inc. and Exelon Corporation (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit 2.2).

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. 001-1839, 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 Baltimore Gas and Electric Company, File No. 1-1910).

3-10		Articles of Restatement to the 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 Baltimore Gas and Electric Company, File No. 1-1910).

3-11		Bylaws of Baltimore Gas and Electric Company, as amended and restated as of May 10, 2012. (File No. 1-16169, 2013 Form 10-K, Exhibit 3-11).

3-12		Operating Agreement, dated as of February 4, 2010, by and among RF HoldCo LLC, Constellation Energy Group, Inc. and GSS Holdings (BGE Utility), Inc. (Designated as Exhibit No. 99.1 to the Current Report on Form 8-K dated February 4, 2010, filed by Baltimore Gas and Electric Company, 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).

494


Exhibit No.	Description

4-1-2	Reserved.

4-1-3	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

	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

	September 15, 2013	000-16844, Form 8-K dated September 23, 2013	4.1

	September 15, 2013	000-16844, Form 8-K dated September 23, 2013	4.1

	September 1, 2014	000-16169, Form 8-K dated September 15, 2014	4.1

4-2	Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-183751, Form S-3, Prospectus).

495


Exhibit No.	Description

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

	January 15, 1994	1-1839, 1993 Form 10-K	4-15

	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

496


Exhibit No.		Description

		Dated as of	File Reference	Exhibit No.

		September 15, 2006	1-1839, Form 8-K dated October 2, 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

		August 1, 2013	001-01839, Form 8-K dated August 19, 2013	4.1

		January 2, 2014	001-01839, Form 8-K dated January 10, 2014	4.1

		October 28, 2014	001-1839, Form 8-K dated November 10, 2014	4.1

	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).

	4-5	Indenture dated December 19, 2003 between Exelon Generation Company, LLC 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 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit 4.1).

	4-8	Form of 5.60% Senior Note due 2042 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit 4.2).

497


Exhibit No.		Description

	4-9	Form of 2.80% Senior Note due 2022 issued by Baltimore Gas and Electric Company. (File 1-1910, Form 8-K dated August 17, 2012, Exhibit 4.1).

	4-10	Form of 3.35% Senior Note due 2023 Baltimore Gas and Electric Company. (File 1-1910, Form 8-K dated June 17, 2013, Exhibit 4.1).

	4-11	Form of 6.000% Senior Secured Notes due 2033 issued by Exelon Generation Company, LLC (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.2).

	4-12	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).

	4-13	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).

	4-14	Indenture dated May 1, 2001 between Exelon Corporation 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).

	4-15	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).

	4-16	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).

	4-17	Indenture dated as of September 28, 2007 from Exelon Generation Company, LLC to U.S. Bank National Association, as trustee (File 333-85496, Form 8-K dated September 28, 2007, Exhibit 4.1).

	4-18	Form of 5.20% Exelon Generation Company, LLC Senior Note due 2019 (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.1).

	4-19	Form of 6.25% Exelon Generation Company, LLC Senior Note due 2039 (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.2).

	4-20	Form of 4.00% Exelon Generation Company, LLC Senior Note due 2020 (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.1).

	4-21	Form of 5.75% Exelon Generation Company, LLC Senior Note due 2041 (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.2).

	4-22	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 Energy Group, Inc., File No. 333-75217.)

	4-23	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 Energy Group, Inc., File No. 333-102723).

	4-24	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 Energy Group, Inc., File No. 333-135991).

498


Exhibit No.		Description

4-25		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 Energy Group, Inc., File No. 1-12869).

4-26		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 Energy Group, Inc., File Nos. 1-12869 and 1-1910).

4-27		Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1).

4-28		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 Baltimore Gas and Electric Company, File No. 1-1910).

4-29		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 Energy Group, Inc., File Nos. 333-157637 and 333-157637-01).

4-30		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 Energy Group, Inc., File No. 333-135991).

4-31		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 Energy Group, Inc., File Nos. 1-12869 and 1-1910).

4-32		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 Energy Group, Inc., File Nos. 333-157637 and 333-157637-01).

4-33		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 Baltimore Gas and Electric Company, File No. 1-1910).

4-34		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 Baltimore Gas and Electric Company, File No. 1 1910).

499


Exhibit No.		Description

4-35		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 Energy Group, Inc., File No. 1-12869).

4-36		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).

4-37		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 Energy Group, Inc., File No. 1-12869).

4-38		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 Baltimore Gas and Electric Company, File No. 1-1910).

4-39-1		Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee. (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1).

4-39-2		First Supplemental Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee.(File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2).

4-39-3		Form of 2.50% Notes due 2024 (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1).

4-39-4		Purchase Contract and Pledge Agreement, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary. (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4).

4-39-5		Form of Remarketing Agreement (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.5).

4-39-6		Form of Corporate Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.6).

4-39-7		Form of Treasury Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.7).

10-1		Facility Credit Agreement, dated as of February 6, 2014, among ExGen Renewables I Holding, LLC and Barclays Bank PLC (File No. 333-85496, Form 8-K dated February 12, 2014, Exhibit 10.1).

10-1-1		Credit Agreement, dated as of September 18, 2014, among ExGen Texas Power, LLC, ExGen Texas Power Holdings, LLC, Wolf Hollow I Power, LLC, Colorado Bend I Power, LLC, Laporte Power, LLC, Handley Power, LLC and Mountain Creek Power, LLC, the lenders party thereto from time to time, Bank of America, N.A., as administrative agent and collateral agent, and Wilmington Trust, National Association, as depositary agent. (File No. 1-16169, Form 8-K dated September 18, 2014, Exhibit 10.1).

10-2		Exelon Corporation Non-Employee Directors’ Deferred Stock Unit Plan (As Amended and Restated Effective January 1, 2011). * (File No. 001-16169, 2010 Form 10-K, Exhibit 10.1).

10-3		Form of Exelon Corporation Unfunded Deferred Compensation Plan for Directors (as amended and restated Effective March 12, 2012). *

10-4		Reserved.

500


Exhibit No.		Description

10-5		Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-1).

10-6		Forms of Transferable Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-2).

10-7		Forms of Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-3).

10-8		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).

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 (As Amended Effective January 1, 2014 * (File No. 1-16169, Exelon Proxy Statement dated April 1, 2014, Appendix A).

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		Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective July 1, 2013. (File No. 1-16169, Schedule 14A dated March 14, 2013 Appendix A).

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 April 1, 2013).* (File No. 001-16169, 2013 Form 10-K, Exhibit 10.21).

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 Exelon Generation Company, LLC and UBS AG, Stamford Branch (File No. 333-85496, Form 8-K dated February 22, 2011, Exhibit No. 10-1).

501


Exhibit No.		Description

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).

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		Reserved.

10-34		Form of Exelon Corporation 2011 Long-Term Incentive Plan, as amended effective December 18, 2014.

10-34-1		Form of Exelon Corporation Long-Term Incentive Program, as amended and restated as of January 1, 2014.

10-35		Form of Change in Control Employment Agreement Effective February 10, 2011. * (File 1-16169, 2011 Form 10-K, Exhibit 10-44).

10-36		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).

10-37		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).

10-38		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).

10-39		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. 001-01839, Form 8-K dated March 28, 2012, Exhibit No. 99-1).

10-40		Amendment No. 3 to Credit Agreement dated as of March 23, 2011 among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated August 10, 2013, Exhibit No. 99-1).

502


Exhibit No.		Description

10-41		Amendment No. 1 to Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, as Borrower, the various financial institutions named therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-1839, Form 8-K dated August 10, 2013, Exhibit No. 99-2).

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 Energy Group, Inc., 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 Energy Group, Inc., File Nos. 1-12869 and 1-1910).

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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., File Nos. 1-12869 and 1-1910).

503


Exhibit No.		Description

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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Baltimore Gas and Electric Company, File No. 1-1910).

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 Baltimore Gas and Electric Company, 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., 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 Energy Group, Inc., File No. 1-12869).

504


Exhibit No.		Description

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).

10-64 - 10-70		Reserved.

10-71-1		Commitment Letter for $7.221 Billion Senior Unsecured Bridge Facility, dated April 29, 2014 (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit No. 10.1).

10-71-2		364-Day Bridge Term Loan Agreement, dated as of May 30, 2014, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and Barclays Bank PLC, as Administrative Agent (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit No. 10.1).

10-71-3		Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Corporation, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.2).

10-71-4		Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Generation Company, LLC, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.3).

10-71-5		Amendment No. 3 to Credit Agreement, dated May 30, 2014, among PECO Energy Company, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.4).

10-71-6		Amendment No. 2 to Credit Agreement, dated as of May 30, 2014, among Baltimore Gas and Electric Company, as Borrower, the financial institutions signatory therein, as Lenders and The Royal Bank of Scotland plc, as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.6).

10-72-1		Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Barclays Capital, Inc., acting as Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.1).

10-72-2		Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Goldman Sachs & Co. (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.2).

10-72-3		Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Barclays Capital, Inc., acting as Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.3).

10-72-4		Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Goldman Sachs & Co. (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.4).

12-1		Exelon Corporation Computation of Ratio of Earnings to Fixed Charges.

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.

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.

505


Exhibit No.		Description

14		Exelon Code of Conduct, as amended March 12, 2012 (File No. 1-16169, Form 8-K dated March 14, 2012, Exhibit No. 14-1).

		Subsidiaries

21-1		Exelon Corporation

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		Anthony K. Anderson

24-2		Ann C. Berzin

24-3		John A. Canning, Jr.

24-4		Christopher M. Crane

24-5		Yves C. de Balmann

24-6		Nicholas DeBenedictis

24-7		Paul L. Joskow

24-8		Reserved.

24-9		Robert J. Lawless

24-10		Richard W. Mies

24-11		William C. Richardson

24-12		John W. Rogers, Jr.

24-13		Mayo A. Shattuck III

24-14		Stephen D. Steinour

		Power of Attorney (Commonwealth Edison Company)

24-15		James W. Compton

24-16		Christopher M. Crane

24-17		A. Steven Crown

24-18		Nicholas DeBenedictis

24-19		Peter V. Fazio, Jr.

24-20		Michael Moskow

24-21		Denis O’Brien

24-22		Anne R. Pramaggiore

24-23		Reserved.

506


Exhibit No.		Description

		Power of Attorney (PECO Energy Company)

24-24		Craig L. Adams

24-25		Christopher M. Crane

24-26		M. Walter D’Alessio

24-27		Nicholas DeBenedictis

24-28		Reserved.

24-29		Reserved.

24-30		Denis O’Brien

24-31		Ronald Rubin

		Power of Attorney (Baltimore Gas and Electric Company)

24-32		Ann C. Berzin

24-33		Christopher M. Crane

24-34		Michael E. Cryor

24-35		James R. Curtiss

24-36		Calvin G. Butler, Jr.

24-37		Joseph Haskins, Jr.

24-38		Carla D. Hayden

24-39		Denis O’Brien

24-40		Michael D. Sullivan

		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, 2013 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 Kenneth W. Cornew 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 Calvin G. Butler, Jr. for Baltimore Gas and Electric Company

31-10		Filed by David M. Vahos 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, 2013 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 Kenneth W. Cornew for Exelon Generation Company, LLC

32-4		Filed by Bryan P. Wright for Exelon Generation Company, LLC

507


Exhibit No.		Description

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 Calvin G. Butler, Jr. for Baltimore Gas and Electric Company

32-10		Filed by David M. Vahos 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

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.

508

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 13th day of February, 2014.


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 13th day of February, 2015.


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		Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/S/ DUANE M. DESPARTE Duane M. DesParte		Senior 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:

Anthony K. Anderson

Ann C. Berzin

John A. Canning, Jr.

Yves C. de Balmann

Nicholas DeBenedictis

Paul L. Joskow

Robert J. Lawless

Richard W. Mies

William C. Richardson

John W. Rogers, Jr.

Mayo A. Shattuck III

Stephen D. Steinour


By:	/S/ DARRYL M. BRADFORD	February 13, 2015
Name:	Darryl M. Bradford

509

SIGNATURES


EXELON GENERATION COMPANY, LLC

By:		/S/ KENNETH W. CORNEW
Name:		Kenneth W. Cornew
Title:		President and Chief Executive Officer


Signature		Title

/S/ KENNETH W. CORNEW Kenneth W. Cornew		President and Chief Executive Officer (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		Chief Accounting Officer (Principal Accounting Officer)

510

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/ GERALD J. KOZEL Gerald J. Kozel		Vice President and Controller (Principal Accounting Officer)

/S/ CHRISTOPHER M. CRANE Christopher M. Crane		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

Nicholas DeBenedictis

Peter V. Fazio, Jr.

Michael Moskow

Denis P. O’Brien


By:	/S/ ANNE R. PRAMAGGIORE	February 13, 2015
Name:	Anne R. Pramaggiore

511

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

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		Denis P. O’Brien
Nicholas DeBenedictis		Ronald Rubin


By:	/S/ CRAIG L. ADAMS	February 13, 2015
Name:	Craig L. Adams

512

SIGNATURES


BALTIMORE GAS AND ELECTRIC COMPANY

By:		/S/ CALVIN G. BUTLER, JR.
Name:		Calvin G. Butler, Jr.
Title:		Chief Executive Officer


Signature		Title

/S/ CALVIN G. BUTLER, JR. Calvin G. Butler, Jr.		Chief Executive Officer (Principal Executive Officer)

/S/ DAVID M. VAHOS David M. Vahos		Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

/S/ MATTHEW N. BAUER Matthew N. Bauer		Vice President and Controller (Principal Accounting Officer)

/S/ CHRISTOPHER M. CRANE Christopher M. Crane		Chairman and Director

This annual report has also been signed below by Calvin G. Butler, Jr., Attorney-in-Fact, on behalf of the following Directors on the date indicated:


Ann C. Berzin		Joseph Haskins, Jr.
Michael E. Cryor		Carla D. Hayden
James R. Curtiss		Denis O’Brien
Michael D. Sullivan


By:	/S/ CALVIN G. BUTLER, JR.	February 13, 2015
Name:	Calvin G. Butler, Jr.

513