Exelon
Annual Report 2014

Plain-text annual report

Morningstar® Document Research℠ FORM 10-KBALTIMORE GAS & ELECTRIC CO - EXCFiled: February 13, 2015 (period: December 31, 2014)Annual report with a comprehensive overview of the companyThe information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The userassumes all risks for any damages or losses arising from any use of this information, except to the extent such damages or losses cannot belimited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549 FORM 10-K xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2014 OR ¨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 PrincipalExecutive Offices; and Telephone Number IRS EmployerIdentification Number1-16169 EXELON CORPORATION(a Pennsylvania corporation)10 South Dearborn StreetP.O. Box 805379Chicago, Illinois 60680-5379(312) 394-7398 23-2990190333-85496 EXELON GENERATION COMPANY, LLC(a Pennsylvania limited liability company)300 Exelon WayKennett Square, Pennsylvania 19348-2473(610) 765-5959 23-30642191-1839 COMMONWEALTH EDISON COMPANY(an Illinois corporation)440 South LaSalle StreetChicago, Illinois 60605-1028(312) 394-4321 36-0938600000-16844 PECO ENERGY COMPANY(a Pennsylvania corporation)P.O. Box 86992301 Market StreetPhiladelphia, Pennsylvania 19101-8699(215) 841-4000 23-09702401-1910 BALTIMORE GAS AND ELECTRIC COMPANY(a Maryland corporation)2 Center Plaza110 West Fayette StreetBaltimore, 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 onWhich RegisteredEXELON CORPORATION: Common Stock, without par value New York and ChicagoSeries A Junior Subordinated Debentures New YorkCorporate Units New YorkPECO 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 PECOEnergy Company New YorkBALTIMORE 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 WarrantsSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIndicate 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 xExelon Generation Company, LLC Yes ¨ No xCommonwealth Edison Company Yes ¨ No xPECO Energy Company Yes ¨ No xBaltimore 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 ExchangeAct of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have beensubject 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 DataFile 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 forsuch 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 becontained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-Kor 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 reportingcompany. 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 ReportingCompanyExelon 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, 2014was as follows: Exelon Corporation Common Stock, without par value $31,319,710,373Exelon Generation Company, LLC Not applicableCommonwealth Edison Company Common Stock, $12.50 par value No established marketPECO Energy Company Common Stock, without par value NoneBaltimore 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 859,833,343Exelon Generation Company, LLC not applicableCommonwealth Edison Company Common Stock, $12.50 par value 127,016,950PECO Energy Company Common Stock, without par value 170,478,507Baltimore Gas and Electric Company, without par value 1,000 Documents Incorporated by ReferencePortions of the Exelon Proxy Statement for the 2015 Annual Meeting ofShareholders and the Commonwealth Edison Company 2015 information statement areincorporated by reference in Part III. Exelon Generation Company, LLC, PECO Energy Company and Baltimore Gas and Electric Company meet the conditions set forth in GeneralInstruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the reduced disclosure format. Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTABLE 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 ISSUERPURCHASES 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 OFOPERATIONS 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 Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents 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 Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents 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 RELATEDSTOCKHOLDER 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 Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGLOSSARY OF TERMS AND ABBREVIATIONS Exelon Corporation and Related EntitiesExelon Exelon CorporationGeneration Exelon Generation Company, LLCComEd Commonwealth Edison CompanyPECO PECO Energy CompanyBGE Baltimore Gas and Electric CompanyBSC Exelon Business Services Company, LLCExelon Corporate Exelon’s holding companyCENG Constellation Energy Nuclear Group, LLCConstellation Constellation Energy Group, Inc.Antelope Valley, AVSR Antelope Valley Solar Ranch OneExelon Transmission Company Exelon Transmission Company, LLCExelon Wind Exelon Wind, LLC and Exelon Generation Acquisition Company, LLCVentures Exelon Ventures Company, LLCAmerGen AmerGen Energy Company, LLCBondCo RSB BondCo LLCComEd Financing III ComEd Financing IIIPEC L.P. PECO Energy Capital, L.P.PECO Trust III PECO Energy Capital Trust IIIPECO Trust IV PECO Energy Capital Trust IVBGE Trust II BGE Capital Trust IIPETT PECO Energy Transition TrustRegistrants Exelon, Generation, ComEd, PECO and BGE, collectivelyOther Terms and Abbreviations1998 restructuring settlement PECO’s 1998 settlement of its restructuring case mandated by the Competition ActAct 11 Pennsylvania Act 11 of 2012Act 129 Pennsylvania Act 129 of 2008AEC Alternative Energy Credit that is issued for each megawatt hour of generation from a qualifiedalternative energy sourceAEPS Pennsylvania Alternative Energy Portfolio StandardsAEPS Act Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amendedAESO Alberta Electric Systems OperatorAFUDC Allowance for Funds Used During ConstructionALJ Administrative Law JudgeAMI Advanced Metering InfrastructureARC Asset Retirement CostARO Asset Retirement ObligationARP Title IV Acid Rain ProgramARRA of 2009 American Recovery and Reinvestment Act of 2009Block contracts Forward Purchase Energy Block ContractsCAIR Clean Air Interstate RuleCAISO California ISOCAMR Federal Clean Air Mercury RuleCERCLA Comprehensive Environmental Response, Compensation and Liability Act of 1980, asamended 1Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOther Terms and AbbreviationsCFL Compact Fluorescent LightClean Air Act Clean Air Act of 1963, as amendedClean Water Act Federal Water Pollution Control Amendments of 1972, as amendedCompetition Act Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996CPI Consumer Price IndexCPUC California Public Utilities CommissionCSAPR Cross-State Air Pollution RuleCTC Competitive Transition ChargeDC Circuit Court United States Court of Appeals for the District of Columbia CircuitDOE United States Department of EnergyDOJ United States Department of JusticeDSP Default Service ProviderDSP Program Default Service Provider ProgramEDF Electricite de France SAEE&C Energy Efficiency and Conservation/Demand ResponseEGR ExGen Renewables I, LLCEGS Electric Generation SupplierEGTP ExGen Texas Power, LLCEIMA Illinois Energy Infrastructure Modernization ActEPA United States Environmental Protection AgencyERCOT Electric Reliability Council of TexasERISA Employee Retirement Income Security Act of 1974, as amendedEROA Expected Rate of Return on AssetsESPP Employee Stock Purchase PlanFASB Financial Accounting Standards BoardFERC Federal Energy Regulatory CommissionFRCC Florida Reliability Coordinating CouncilFTC Federal Trade CommissionGAAP Generally Accepted Accounting Principles in the United StatesGDP Gross Domestic ProductGHG Greenhouse GasGRT Gross Receipts TaxGSA Generation Supply AdjustmentGWh Gigawatt hourHAP Hazardous air pollutantsHealth Care Reform Acts Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Actof 2010IBEW International Brotherhood of Electrical WorkersICC Illinois Commerce CommissionICE Intercontinental ExchangeIllinois Act Illinois Electric Service Customer Choice and Rate Relief Law of 1997Illinois EPA Illinois Environmental Protection AgencyIllinois Settlement Legislation Legislation enacted in 2007 affecting electric utilities in IllinoisIntegrys Integrys Energy Services, Inc.IPA Illinois Power AgencyIRC Internal Revenue CodeIRS Internal Revenue Service 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOther Terms and AbbreviationsISO Independent System OperatorISO-NE ISO New England Inc.ISO-NY ISO New YorkkV KilovoltkW KilowattkWh Kilowatt-hourLIBOR London Interbank Offered RateLILO Lease-In, Lease-OutLLRW Low-Level Radioactive WasteLTIP Long-Term Incentive PlanMATS U.S. EPA Mercury and Air Toxics Standard RuleMBR Market Based Rates IncentiveMDE Maryland Department of the EnvironmentMDPSC Maryland Public Service CommissionMGP Manufactured Gas PlantMISO Midcontinent Independent System Operator, Inc.mmcf Million Cubic FeetMoody’s Moody’s Investor ServiceMOPR Minimum Offer Price RuleMRV Market-Related ValueMW MegawattMWh Megawatt hourNAAQS National Ambient Air Quality Standardsn.m. not meaningfulNAV Net Asset ValueNDT Nuclear Decommissioning TrustNEIL Nuclear Electric Insurance LimitedNERC North American Electric Reliability CorporationNGS Natural Gas SupplierNJDEP New Jersey Department of Environmental ProtectionNon-Regulatory Agreements Units Nuclear generating units or portions thereof whose decommissioning-related activities are notsubject 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 ViolationNPDES National Pollutant Discharge Elimination SystemNRC Nuclear Regulatory CommissionNSPS New Source Performance StandardsNWPA Nuclear Waste Policy Act of 1982NYMEX New York Mercantile ExchangeOCI Other Comprehensive IncomeOIESO Ontario Independent Electricity System OperatorOPEB Other Postretirement Employee BenefitsPA DEP Pennsylvania Department of Environmental ProtectionPAPUC Pennsylvania Public Utility CommissionPGC Purchased Gas Cost ClausePJM PJM Interconnection, LLCPOLR Provider of Last Resort 3Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOther Terms and AbbreviationsPOR Purchase of ReceivablesPPA Power Purchase AgreementPPL PPL Holtwood, LLCPrice-Anderson Act Price-Anderson Nuclear Industries Indemnity Act of 1957PRP Potentially Responsible PartiesPSEG Public Service Enterprise Group IncorporatedPURTA Pennsylvania Public Realty Tax ActPV PhotovoltaicRCRA Resource Conservation and Recovery Act of 1976, as amendedREC Renewable Energy Credit which is issued for each megawatt hour of generation from a qualifiedrenewable energy sourceRegulatory Agreement Units Nuclear generating units whose decommissioning-related activities are subject to contractualelimination 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 SuppliersRFP Request for ProposalRider Reconcilable Surcharge Recovery MechanismRGGI Regional Greenhouse Gas InitiativeRMC Risk Management CommitteeRPM PJM Reliability Pricing ModelRPS Renewable Energy Portfolio StandardsRTEP Regional Transmission Expansion PlanRTO Regional Transmission OrganizationS&P Standard & Poor’s Ratings ServicesSEC United States Securities and Exchange CommissionSenate Bill 1 Maryland Senate Bill 1SERC SERC Reliability Corporation (formerly Southeast Electric Reliability Council)SERP Supplemental Employee Retirement PlanSGIG Smart Grid Investment GrantSGIP Smart Grid Initiative ProgramSILO Sale-In, Lease-OutSMP Smart Meter ProgramSMPIP Smart Meter Procurement and Installation PlanSNF Spent Nuclear FuelSOA Society of ActuariesSOS Standard Offer ServiceSPP Southwest Power PoolTax Relief Act of 2010 Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010Upstream Natural gas and oil exploration and production activitiesVIE Variable Interest EntityWECC Western Electric Coordinating Council 4Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFILING FORMAT This combined Annual Report on Form 10-K is being filed separately by the Registrants. Information contained herein relating to anyindividual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any otherRegistrant. FORWARD-LOOKING STATEMENTS This Report contains certain forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that aresubject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by aRegistrants 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. FinancialStatements and Supplementary Data: Note 22; and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautionednot to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrantsundertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of thisReport. 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 at100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SECat 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by theSEC at www.sec.gov and the Registrants’ websites at www.exeloncorp.com. Information contained on the Registrants’ websites shall not bedeemed incorporated into, or to be a part of, this Report. 5Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART 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 energygeneration business, and through ComEd, PECO and BGE, in the energy delivery businesses discussed below. Exelon’s principal executiveoffices 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 regionsthrough its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation alsosells 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 corporaterestructuring, effective January 1, 2001, in which Exelon separated its generation and other competitive businesses from its regulated energydelivery businesses at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is610-765-5959. ComEd ComEd’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricitytransmission 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 corporationnamed Commonwealth Edison Company, which was incorporated in 1907. ComEd’s principal executive offices are located at 440 South LaSalleStreet, 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 transmissionand distribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase andregulated retail sale of natural gas and the provision of natural gas distribution services to retail customers in the Pennsylvania countiessurrounding 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. 6Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBGE BGE’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmissionand distribution services to retail customers in central Maryland, including the City of Baltimore, as well as the purchase and regulated retail saleof 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, Maryland21201, 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’soperating 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) tocombine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Themerger is expected to be completed in the second or third quarter of 2015. See Note 4—Mergers, Acquisitions, and Dispositions of the CombinedNotes 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 sellselectricity 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 generationfleet by expanding Generation’s regional and technological footprint. Generation leverages its energy generation portfolio to ensure delivery ofenergy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation’s customerfacing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates inwell-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation’s fleet, including itsnuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors helpGeneration 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 andproduction activities (Upstream). Generation is a public utility under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales ofelectricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or denymarket-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction overratemaking also includes the authority to suspend the market-based rates of utilities and set cost-based rates should FERC find that its previousgrant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are 7Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsnot limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utilityor an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internalcorporate reorganizations; and certain holding company acquisitions of public utility and holding company securities. Additionally, ERCOT is notsubject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. Specificoperations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC andFederal and state environmental protection agencies. Additionally, Generation is subject to mandatory reliability standards promulgated by theNERC, 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-NEand SPP, have been approved by FERC as RTOs, and CAISO and ISO-NY have been approved as ISOs. These entities are responsible forregional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, marketmonitoring, the scheduling of physical power sales brokered through ICE and NYMEX and the elimination or reduction of redundant transmissioncharges 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 transactionscontemplated by the Agreement and Plan of Merger. Since the merger transaction, Generation includes the former Constellation generation andcustomer supply operations. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statementsfor 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 areappointed by Generation and five by EDF. CENG owns a total of five nuclear generating facilities on three sites, Calvert Cliffs, R.E. Ginna andNine Mile Point. CENG’s ownership share in the total capacity of these units is 3,998 MW. See ITEM 2. PROPERTIES for additional informationon these sites. Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. The transfer ofthe nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment inCENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s and Generation’s ConsolidatedBalance Sheets. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated FinancialStatements 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 businessactivities 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 excludedfrom the transaction. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements foradditional information on the above acquisition. 8Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAntelope Valley Solar Ranch One. On September 30, 2011, Exelon announced the completion of its acquisition of all of the interests inAntelope Valley, a 242-MW solar project under development in northern Los Angeles County, California, from First Solar, Inc. The facility becamefully operational in 2014. The project has a 25-year PPA with Pacific Gas & Electric Company for the full output of the plant, which has beenapproved 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 increasedGeneration’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 totalexpected pre-tax proceeds of $1.8 billion (after-tax proceeds of approximately $1.4 billion). The proceeds are expected to be used primarily tofinance 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 RavenPower Holdings LLC, a subsidiary of Riverstone Holdings LLC to comply with certain of the regulatory approvals required by the merger withConstellation 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 ConsolidatedFinancial 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 Nuclear 19,316 Fossil 9,515 Renewable 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 thedifferent geographical areas in which Generation’s customer-facing activities are conducted and where Generation’s generating resources arelocated. • Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, WestVirginia, Delaware, the District of Columbia and parts of North Carolina (approximately 35% of capacity). 9 (a)(b)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents • Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky andTennessee; 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 byPJM; 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% ofcapacity). • 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 fromexternal 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 of19,316 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 onExelon’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 ofApril 1, 2014. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statementsfor additional information. Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated byPSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2014, 2013, and 2012 electric supply (in GWh) generatedfrom 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 supportGeneration’s wholesale and retail power marketing activities. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION 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 cannegotiate favorable terms for the materials and services that its business requires. Generation’s operations from its nuclear plants have historicallyhad minimal environmental impact and the plants have a safe operating history. 10Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDuring 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 managesits scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generationbase for Generation’s wholesale and retail marketing and trading activities. During scheduled refueling outages, Generation performs maintenanceand 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, Generationhas extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation has extensive safetysystems 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 nucleargenerating stations, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review andregulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects ofthose stations. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results, andcommunicates its assessment on a semi-annual basis. As of December 31, 2014, the NRC categorized Calvert Cliffs unit 2, Clinton, Limerickunits 1 and 2, and Oyster Creek in the Regulatory Response Column, which is the second highest of five performance bands. All other unitsoperated by Generation are categorized in the Licensee Response Column as of December 31, 2014, which is the highest performance band. TheNRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, theregulations under such Act or the terms of the operating licenses. Changes in regulations by the NRC may require a substantial increase in capitalexpenditures 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 theFukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. In July 2011, an NRC Task Force formed in theaftermath of the Fukushima Daiichi events issued a report of its review of the accident, including recommendations for future regulatory action bythe 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 safelyand do not present an imminent risk to public health and safety. The NRC and its staff have issued orders and implementation guidance forcommercial reactor licensees operating in the United States. The NRC and its staff are continuing to evaluate additional requirements. Foradditional 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. 11Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsLicenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating licenserenewals 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 operatinglicenses from the NRC and has received 20-year operating license renewals for Salem Units 1 and 2. On December 8, 2010, Exelon announcedthat Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The following table summarizes the currentoperating license expiration dates for Generation’s nuclear facilities in service: Station Unit In-ServiceDate Current LicenseExpiration Braidwood 1 1988 2026 2 1988 2027 Byron 1 1985 2024 2 1987 2026 Calvert Cliffs 1 1975 2034 2 1977 2036 Clinton 1 1987 2026 Dresden 2 1970 2029 3 1971 2031 LaSalle 1 1984 2022 2 1984 2023 Limerick 1 1986 2044 2 1990 2049 Nine Mile Point 1 1969 2029 2 1988 2046 Oyster Creek 1 1969 2029 Peach Bottom 2 1974 2033 3 1974 2034 Quad Cities 1 1973 2032 2 1973 2032 R.E. Ginna 1 1970 2029 Salem 1 1977 2036 2 1981 2040 Three Mile Island 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 operatinglicense renewal process takes approximately four to five years from the commencement of the renewal process until completion of the NRC’sreview. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expectedto 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 OysterCreek. 12 (a) (b) (b) (c) (c) (d) (c) (c) (c)(e) (c) (c) (c) (c) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIn August 2012, Generation entered into an operating services agreement with the Omaha Public Power District (OPPD) to provideoperational and managerial support services for the Fort Calhoun Station and a licensing agreement for use of the Exelon Nuclear ManagementModel. 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 ofexpertise gained from a half-century of nuclear power operations. Based on ongoing reviews, the nuclear uprate implementation plan was adjustedduring 2013 to cancel certain projects. The Measurement Uncertainty Recapture uprate projects at the Dresden and Quad Cities nuclear stationswere cancelled as a result of the cost of additional plant modifications identified during final design work which, when combined with then currentmarket conditions, made the projects not economically viable. Additionally, the market conditions prompted Generation to cancel the previouslydeferred extended power uprate projects at the LaSalle and Limerick nuclear stations. During 2013, Generation recorded a pre-tax charge tooperating and maintenance expense and interest expense of approximately $111 million and $8 million, respectively, to accrue remaining costsand 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. AtDecember 31, 2014, Generation has capitalized $122 million to construction work in progress within property, plant and equipment for nuclearuprate projects expected to be placed in service by the end of 2016, consisting of 139 MWs of new nuclear generation that is in the installationphase 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 becompleted as planned, previously capitalized costs will be reversed through earnings as a charge to operating and maintenance expense andinterest. Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the UnitedStates, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities in on-sitestorage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the lifeof 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 caskstorage (this includes SNF assemblies at Zion Station, for which Generation retains ownership even though the responsibility for decommissioningZion Station has been assumed by another party; see Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated FinancialStatements for additional information regarding Zion Station Decommissioning). All currently operating Generation-owned nuclear sites have on-sitedry cask storage, except for Clinton and Three Mile Island. Clinton and Three Mile Island are anticipated to lose full core reserve, which is whenthe 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 offloadcapability in their respective on-site storage pools. On-site dry cask storage in concert with on-site storage pools will be capable of meeting allcurrent 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 andContingencies of the Combined Notes to Consolidated Financial Statements. 13Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAs a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station andpermanently disposed of at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states mayenter 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 beoperational until after 2020. Generation ships its Class A LLRW, which represents 93% of LLRW generated at its stations, to disposal facilities in Utah and SouthCarolina. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (whichincludes 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 inGeneration’s nuclear fleet, as approved by the NRC. Generation has a contract through 2032 to ship Class B and Class C LLRW to a disposalfacility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently stored at the Peach Bottom and LaSallestations as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW fromGeneration’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still berequired to utilize on-site storage at its Peach Bottom and LaSalle stations for Class B and Class C LLRW. Generation currently has enoughstorage capacity to store all Class B and C LLRW for the life of all stations in Generation’s nuclear fleet. Generation continues to pursuealternative 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 nuclearstations, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industryrisk-sharing provisions. See “Nuclear Insurance” within Note 22—Commitments and Contingencies of the Combined Notes to ConsolidatedFinancial Statements for details. For information regarding property insurance, see ITEM 2. PROPERTIES—Generation. Generation is self-insured to the extent that anylosses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have amaterial 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 willbe available in specified minimum amounts at the end of the life of the facility to decommission the facility. See ITEM 7. MANAGEMENT’SDISCUSSION 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 AccountingPolicies and Estimates, Nuclear Decommissioning, Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; andNote 3—Regulatory Matters, Note 11—Fair Value of Financial Assets and Liabilities and Note 15—Asset Retirement Obligations of the CombinedNotes 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 storageuntil a permanent repository under the NWPA is completed. All SNF for Peach Bottom Unit 1, which ceased operation in 1974, has been removedfrom the site and the SNF pool is drained and decontaminated. Generation’s estimated ARO liabilities to 14Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsdecommission Dresden Unit 1 and Peach Bottom Unit 1 as of December 31, 2014 were $188 million and $111 million, respectively. As ofDecember 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 ZionSolutionsassumed 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, Generationtransferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDTfunds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding theobligation to dispose of SNF, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from theZion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject tocertain restrictions on its ability to request reimbursement; specifically, if certain milestones as defined in the ASA are not met, all or a portion ofrequested reimbursements shall be deferred until such milestones are met. See Note 15—Asset Retirement Obligations of the Combined Notes toConsolidated Financial Statements for additional information regarding Zion Station Decommissioning and see Note 2—Variable Interest Entities ofthe 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 (excludingQuail 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 windproject entities with minority interest owners, see Note 2—Variable Interest Entities of the Combined Notes to Consolidated Financial Statementsfor additional information on these wind project entities. Generation’s fossil and renewable generating stations are all operated by Generation, withthe exception of LaPorte, Sunnyside and Wyman, which are operated by third parties. See Note 4—Mergers, Acquisitions, and Dispositions of theCombined Notes to Consolidated Financial Statements for additional information relating to the sale of the Quail Run generating facility. In 2014and 2013, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 13% and 15%, respectively, ofGeneration’s total electric supply. The majority of this output was dispatched to support Generation’s wholesale and retail power marketingactivities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. PROPERTIES—Exelon GenerationCompany, 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 navigablewaterways or Federal lands, or connected to the interstate electric grid. On August 29, 2012 and August 30, 2012, Generation submittedhydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy RunPumped Storage Facility Project (Muddy Run), respectively. Based on the FERC procedural schedule, the FERC licensing process was notcompleted 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 15Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsuntil the new licenses are issued. On September 10, 2014, FERC issued annual licenses for Conowingo and Muddy Run, effective as of theexpiration of the previous licenses. If FERC does not issue new licenses prior to the expiration of annual licenses, the annual licenses will renewautomatically. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. Refer toNote 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 renewableprojects currently under construction. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectricoperations, unless required by financing agreements. Generation maintains both property damage and liability insurance. For property damage andliability claims for these operations, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount ofinsurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s financial condition and their results ofoperations 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 notown under long-term contracts. The following tables summarize Generation’s long-term contracts to purchase unit-specific physical power with anoriginal term in excess of one year in duration, by region, in effect as of December 31, 2014: Region Number ofAgreements 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 166,454 142,126 Purchases—non-trading portfolio 48,200 69,791 Fossil (primarily natural gas) 26,324 30,785 Renewable 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 thatare 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, Generationassumed 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. 16(a) (b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe fuel costs per MWh for nuclear generation are less than those for fossil-fuel generation. Consequently, nuclear generation is generallythe 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, theconversion 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’senrichment requirements have been contracted through 2020. Contracts for fuel fabrication have been obtained through 2018. Generation does notanticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services to meet the nuclear fuelrequirements 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 sothat in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months totake advantage of favorable market pricing. Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures. Generation also hedgesforward price risk, using both over-the-counter and exchange-traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates andNote 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regardingderivative financial instruments. Power Marketing Generation’s integrated business operations include the physical delivery and marketing of power obtained through its generation capacityand through long-term, intermediate-term and short-term contracts. Generation maintains an effective supply strategy through ownership ofgeneration assets and power purchase and lease agreements. Generation has also contracted for access to additional generation through bilaterallong-term PPAs. PPAs, including tolling agreements, are commitments related to power generation of specific generation plants and/or aredispatchable in nature similar to asset ownership depending on the type of underlying asset. Generation secures contracted generation as part ofits overall strategic plan, with objectives such as obtaining low-cost energy supply sources to meet its physical delivery obligations to bothwholesale and retail customers and assisting customers to meet renewable portfolio standards. Generation may also buy power to meet the energydemand of its customers. Generation sells electricity, natural gas, and related products and solutions to various customers, including distributionutilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets. Generation’scustomer facing operations combine a unified sales force with a customer-centric model that leverages technology to broaden the range ofproducts and solutions offered, which Generation believes promotes stronger customer relationships. This model focuses on efficiency and costreduction, 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 purchasestransmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet 17Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentscustomer delivery needs in markets without an organized RTO. Generation also incorporates contingencies into its planning for extreme weatherconditions, 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 marketingactivities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation also entersinto transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 2015 and beyond for portions of itselectricity portfolio that are unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk insubsequent years. This strategy has not changed as a result of recent and pending asset divestitures. As of December 31, 2014, the percentageof 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 divestitureimpact of Quail Run). Expected generation is the volume of energy that best represents our commodity position in energy markets from owned orcontracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibratedto market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economichedges and certain non-derivative contracts, including sales to ComEd, PECO and BGE to serve their retail load. A portion of Generation’shedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices, whichroutinely change in the market. The corporate risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retailpower marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts foronly a small portion of Generation’s efforts. The proprietary trading portfolio is subject to a risk management policy that includes stringent riskmanagement limits, including volume, stop-loss and value-at-risk limits, to manage exposure to market risk. See ITEM 7A. QUANTITATIVE ANDQUALITATIVE 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 tounaffiliated utilities and others were as follows: (in millions) Net CapacityPurchases RECPurchases Transmission RightsPurchases 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 representGeneration’s expected payments under these arrangements at December 31, 2014, net of fixed capacity payments expected to be received (“Capacity offsets”) by Generationunder 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 capacitycharges which may be reduced based on plant availability. 18(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(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 otherinternal infrastructure projects. Generation’s estimated capital expenditures for 2015 are as follows: (in millions) Nuclear fuel $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 andtransmission services to a diverse base of residential, commercial and industrial customers in northern Illinois. ComEd is a public utility under theIllinois Public Utilities Act subject to regulation by the ICC related to distribution rates and service, the issuance of securities, and certain otheraspects of ComEd’s business. ComEd is a public utility under the Federal Power Act subject to regulation by FERC related to transmission ratesand 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 serviceterritory includes the City of Chicago, an area of about 225 square miles with an estimated population of 2.7 million. ComEd has approximately3.8 million customers. ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generallynonexclusive 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 bodiesto 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 extremescreate demand for either summer cooling or winter heating. ComEd’s highest peak load occurred on July 20, 2011, and was 23,753 MWs; itshighest 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 generationsuppliers. All ComEd customers have the ability to purchase electricity from a competitive electric generation supplier. The number of retailcustomers 19 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsparticipating 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 suppliersrepresented 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 onelectric revenue net of purchased power expense or ComEd’s financial position. ComEd’s cost of electric supply is passed without markup directlythrough to those customers not served by a competitive electric generation supplier and those rates are subject to adjustment monthly to recoveror refund the difference between ComEd’s actual cost of electricity delivered and the amount included in rates. For those customers that choose acompetitive 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 fromexternal 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 providegeneration supply service, which is referred to as a POLR obligation, primarily varies by customer size. ComEd’s obligation to provide suchservice to residential customers and other small customers with demands of under 100 kWs continues for all customers who do not choose acompetitive 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, asthis group of customers has previously been declared competitive. Customers with competitive declarations may still purchase power and energyfrom ComEd, but only at hourly market prices. Energy Infrastructure Modernization Act (EIMA). Since 2011, ComEd’s distribution rates are established through a performance-based rateformula 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-incomecustomers, 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, unlessapproved to continue through 2022 by the Illinois General Assembly. During the fourth quarter of 2014, the Illinois House and Senate each passedHouse 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. TheGovernor 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 determinesare prudently and reasonably incurred for such year. ComEd’s allowed rate of return on common equity is the annual average rate on 30-yeartreasury notes plus 580 basis points, subject to a (collar) of plus or minus 50 basis points. The collar, therefore limits favorable and unfavorableimpacts of weather and load on distribution revenue. In addition, ComEd’s allowed rate of return on common equity is subject to reduction ifComEd does not deliver the reliability and customer service benefits, as defined, it has committed to over the ten-year life of the investmentprogram. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 20Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsProcurement-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 processunder which ComEd procures its electricity supply from various suppliers, including Generation. Charges incurred for electric supply procuredthrough contracts with Generation are included in Purchased power from affiliates on ComEd’s Statement of operations and ComprehensiveIncome. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’sprocurement plans. Continuous Power Interruption. The Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences acontinuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actualdamages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency andcontingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seekfrom the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weatherevents or conditions, customer tampering, or certain other causes enumerated in the law. See Note 22—Commitments and Contingencies of theCombined 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 gridtechnology. On June 11, 2014, the ICC approved ComEd’s request to accelerate the deployment, which allows for the installation of more than fourmillion smart meters throughout ComEd’s service territory by 2018, three years in advance of the originally scheduled 2021 completion date. Todate, 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 tomeet 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, theICC approved ComEd’s third three-year Energy Efficiency and Demand Response Plan covering the period June 2014 through May 2017. Theplans are designed to meet Illinois’ energy efficiency and demand response goals through May 2017, including reductions in delivered energy to allretail 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 annuallythereafter, as part of the IPA procurement plan, ComEd is to include cost-effective expansion of current energy efficiency programs, and additionalnew cost-effective and/or third-party energy efficiency programs that are identified through a request for proposal process. All cost-effective energyefficiency programs are included in the IPA procurement plan for consideration of implementation. While these programs are monitored separatelyfrom the Energy Efficiency Portfolio Standard (EEPS), funds for both the EEPS portfolio and IPA energy efficiency programs are collected underthe same rider. 21Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsConstruction Budget ComEd’s business is capital intensive and requires significant investments, primarily in electricity transmission and electricity distributionfacilities, to ensure the adequate capacity, reliability and efficiency of its system. Such investments include capital program and modernizationpursuant 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 CapitalResources for further information. PECO PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity transmission anddistribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulatedretail sale of natural gas and the provision of gas distribution services to retail customers in the Pennsylvania counties surrounding the City ofPhiladelphia. PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the PAPUC as to electric and gasdistribution rates and service, the issuances of certain securities and certain other aspects of PECO’s operations. PECO is a public utility underthe 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 ofvarious 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 estimatedpopulation of 4.0 million. PECO provides electric distribution service in an area of approximately 1,900 square miles, with a population ofapproximately 4.0 million, including approximately 1.6 million in the City of Philadelphia. PECO provides natural gas distribution service in an areaof approximately 1,900 square miles in southeastern Pennsylvania adjacent to the City of Philadelphia, with a population of approximately 2.4million. 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 orterritories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued bythe PAPUC and/or “grandfathered rights,” with all of such rights generally unlimited as to time and generally exclusive from competition from otherelectric and natural gas utilities. In a few defined municipalities, PECO’s natural gas service territory authorizations overlap with that of anothernatural 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 createdemand for either summer cooling or winter heating. PECO’s highest peak load occurred on July 22, 2011 and was 8,983 MW; its highest peakload 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’shighest daily natural gas send out occurred on January 7, 2014 and was 760 mmcf. 22Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsRetail Electric Services PECO’s retail electric sales and distribution service revenues are derived pursuant to rates regulated by the PAPUC. Pennsylvania permitscompetition by competitive electric generation suppliers for the supply of retail electricity while retail transmission and distribution service remainsregulated under the Competition Act. At December 31, 2014, there were 101 competitive electric generation suppliers serving PECO customers. AtDecember 31, 2014, the number of retail customers purchasing energy from a competitive electric generation supplier was 546,900 representingapproximately 34% of total retail customers. Retail deliveries purchased from competitive electric generation suppliers represented approximately70% of PECO’s retail kWh sales for the year ended December 31, 2014. Customers that choose a competitive electric generation supplier are notsubject to rates for PECO’s electric supply procurement costs and retail transmission service charges. PECO presents on customer bills itselectric supply Price to Compare, which is updated quarterly, to assist customers with the evaluation of offers from competitive electric generationsuppliers. Customer choice program activity affects revenue collected from customers related to supplied energy; however, that activity has no impacton PECO’s electric revenue net of purchased power expense or financial position. PECO’s cost of electric supply is passed directly through todefault service customers without markup and those rates are subject to adjustment at least quarterly to recover or refund the difference betweenPECO’s actual cost of electricity delivered and the amount included in rates through the GSA. For those customers that choose a competitiveelectric generation supplier, PECO acts as the billing agent but does not record revenue or purchased power expense related to this electricsupply. 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 fromexternal customers, net income and total assets. Procurement-Related Proceedings. PECO’s electric supply for its customers is procured through contracts executed in accordance with itsPAPUC-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 planoutlined how PECO purchased electric supply for default service customers from June 1, 2013 through May 31, 2015. Pursuant to the secondDSP Program, PECO procured electric supply through five competitive procurements for fixed price full requirements contracts of two years orless for the residential and small and medium commercial classes and spot market price full requirement contracts for the large commercial andindustrial 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’sStatement of Operations and Comprehensive Income. The second DSP Program also includes a number of retail market enhancements recommended by the PAPUC in its previously issuedRetail Markets Intermediate Work Plan Order. PECO was also directed to allow its low-income Customer Assistance Program (CAP) customers topurchase their generation supply from competitive electric generation suppliers beginning April 1, 2014. On May 1, 2013, PECO filed a Petition forApproval of its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, withmodifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, low-income advocacy groups filed an appeal andemergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not containsufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review ofthe appeal. Pending the Commonwealth Court’s review, PECO will not implement CAP Shopping. The Commonwealth Court’s decision is expectedin 2015. 23Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOn March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 throughMay 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. On August 28, 2014, PECO filed a Joint Petitionfor Partial Settlement, which affirmed PECO’s procurement plan for residential and small commercial customers. On December 4, 2014, thePAPUC approved PECO’s third DSP Program, as modified by the Joint Petition for Partial Settlement, without modification or limitation. Separatefrom the Joint Petition for Partial Settlement, the PAPUC also approved other items related to the program. The plan outlines how PECO willpurchase electric supply for default service customers. PECO will procure electric supply through four competitive procurements for fixed price fullrequirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price fullrequirement 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, whichwas filed in accordance with the requirements of Act 129. Also, in April 2010, PECO entered into a Financial Assistance Agreement with the DOEfor SGIG funds under the ARRA of 2009. Under the SGIG, PECO was awarded $200 million, the maximum grant allowable under the program, forits SGIG project—Smart Future Greater Philadelphia. As of December 31, 2014, PECO has received all of the $200 million, including $4 million forsub-recipients, in reimbursements. The SGIG funds have been used by PECO to offset the total impact to ratepayers of the smart meterdeployment required by Act 129. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deploymentplan with the PAPUC, which was approved without modification on August 15, 2013. Under PECO’s universal deployment plan, PECO will deployall 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 ofDecember 31, 2014, PECO has spent $540 million and $119 million on smart meter and smart grid infrastructure, respectively, not including theDOE 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 concludedon 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 demandin 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 fullcompliance with all Phase I targets. The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provides energy consumption reduction requirementsfor the second phase of Act 129’s EE&C programs, which went into effect on June 1, 2013 with a three-year cumulative consumption reductiontarget of 1,125,852 MWh. On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposeddemand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale pricessuppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to 24Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsmake a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO’sEE&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 programfor mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program bymodifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy EfficiencyProgram 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 causingcertain shopping customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughoutPennsylvania, on April 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking orderrequires electric generation suppliers to provide more consumer education regarding their contracts. The second rulemaking order requires electricdistribution companies to enable customers to switch suppliers within three business days (known as accelerated switching). The improvedcustomer education and accelerated switching were to be in place within 30 days and six months of approval of the orders, respectively. Theorders became final on June 14, 2014. On December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on SupplierSwitch), 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 torecover or refund the difference between the actual cost of purchased natural gas and the amount included in rates without markup through thePGC. PECO’s natural gas customers have the right to choose their natural gas suppliers or to purchase their gas supply from PECO at cost. AtDecember 31, 2014, the number of retail customers purchasing natural gas from a competitive natural gas supplier was 78,400, representingapproximately 15% of total retail customers. Retail deliveries purchased from competitive natural gas suppliers represented approximately 22% ofPECO’s mmcf sales for the year ended December 31, 2014. PECO provides distribution, billing, metering, installation, maintenance andemergency 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 firmtransportation contracts for terms of up to three years in accordance with its annual PAPUC PGC settlement. PECO’s aggregate annual firmsupply 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 undercontract 21 million dekatherms of underground storage through service agreements. Natural gas from underground storage representsapproximately 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 providemore incentives to customers interested in switching to natural gas service. If approved, local customers would pay significantly less initially tohave natural gas installed at their homes and businesses. 25Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSee 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 gasdistribution facilities to ensure the adequate capacity, reliability and efficiency of its system. PECO, as a transmission facilities owner, has variousconstruction commitments under PJM’s RTEP. PECO’s most recent estimate of capital expenditures for plant additions and improvements for2015 is $550 million, which includes RTEP projects and capital expenditures related to the smart meter and smart grid project. 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 CapitalResources for further information. BGE BGE is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity transmission and distributionservices to retail customers in central Maryland, including the City of Baltimore, as well as the purchase and regulated retail sale of natural gasand the provision of gas distribution services to retail customers in central Maryland, including the City of Baltimore. BGE is a public utility underthe Public Utilities Article of the Maryland Annotated Code subject to regulation by the MDPSC as to electric and gas distribution rates andservice, the issuances of certain securities and certain other aspects of BGE’s operations. BGE is a public utility under the Federal Power Actsubject to regulation by FERC as to transmission rates and certain other aspects of BGE’s business and by the U.S. Department of Transportationas 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 provideselectric distribution service in an area of approximately 2,300 square miles and gas distribution service in an area of approximately 800 squaremiles, both with a population of approximately 2.8 million, including approximately 621,000 in the City of Baltimore. BGE delivers electricity toapproximately 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 andterritories in which it now supplies such services. With respect to electric distribution service, BGE’s authorizations consist of charter rights, astate-wide franchise grant and a franchise grant from the City of Baltimore. The franchise rights are nonexclusive and are perpetual. With respectto natural gas distribution service, BGE’s authorizations consist of charter rights, a perpetual state-wide franchise grant, and franchises granted byall the municipalities and/or governmental bodies in which BGE now supplies services. The franchise grants are not exclusive; some are perpetualand 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 createdemand 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 loadduring winter months occurred on January 7, 2014 and was 6,526 MW. 26Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBGE’s natural gas sales are generally higher during the winter months when cold temperatures create demand for winter heating. BGE’shighest 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 monthlyadjustment to its electric and gas distribution revenues from all residential customers, commercial electric customers, the majority of largeindustrial electric customers, and all firm service commercial gas customers to eliminate the effect of abnormal weather and usage patterns percustomer on BGE’s electric and gas distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, bycustomer class, regardless of changes in consumption levels. This adjustment allows BGE to recognize revenues at MDPSC-approved levels percustomer, regardless of what actual distribution volumes are for a billing period (referred to as “revenue decoupling”). Therefore, while theserevenues are affected by customer growth, they will not be affected by actual weather or usage conditions. BGE bills or credits affected customersin 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 aresult of the deregulation of electric generation in Maryland effective July 1, 2000, all customers can choose a competitive electric generationsupplier. While BGE does not sell electric supply to all customers in its service territory, BGE continues to deliver electricity to all customers andprovides meter reading, billing, emergency response, and regular maintenance services. Customer choice program activity affects revenuecollected from customers related to supplied energy; however, that activity has minimal impact on BGE’s electric revenue net of purchased powerexpense or financial position. At December 31, 2014, there were 59 competitive electric generation suppliers serving BGE customers. AtDecember 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 approximately60% 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 fromexternal 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 chargedrecover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes a commercial and industrialshareholder return component and an incremental cost component. Bidding to supply BGE’s market-based SOS occurs through a competitivebidding process approved by the MDPSC. Successful bidders, which may include Generation, will execute contracts with BGE for terms of threemonths or two years. BGE is obligated by the MDPSC to provide several variations of SOS to commercial and industrial customers depending oncustomer load. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates onBGE’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’sprocurement plan. Electric Distribution Rate Case. On July 2, 2014, and as amended on September 15, 2014, BGE filed for an electric base rate increase withthe MDPSC, ultimately requesting an increase of $99 million. On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement(the 27Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSettlement Agreement) reached with all parties to the case under which it would receive an increase of $22 million in electric base rates. TheSettlement Agreement establishes new depreciation rates which have the effect of decreasing annual electric depreciation expense byapproximately $22 million. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreementwithout modification, which became a final order on December 12, 2014. The approved electric distribution rate became effective for servicesrendered 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-waycommunications network, 2 million smart electric and gas meters and modules, new customer pricing programs, a new customer web portal andnumerous enhancements to BGE operations. Also, in April 2010, BGE entered into a Financial Assistance Agreement with the DOE for SGIGfunds under the ARRA of 2009. Under the SGIG, BGE was awarded $200 million, the maximum grant allowable under the program, to support itsSmart Grid, Peak Rewards and CC&B initiatives, of which BGE had been fully reimbursed for as of December 31, 2013. The SGIG fundingsignificantly 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’sSmart Meter Programs. Energy Efficiency Programs. BGE’s energy efficiency programs include a lighting program, retrofit programs, incentives for energy efficientnew homes, rebates for heating and cooling systems, energy audits, an energy efficient appliance rebate and trade-in program, customerincentives for non-profit, educational, governmental and business customers, energy management programs and bill credits to help residentialcustomers reduce energy demand during peak periods. The MDPSC initially approved a full portfolio of conservation programs in 2008 as well as acustomer surcharge to recover the associated costs in 2009. This customer surcharge is updated annually. In December 2011, the MDPSCapproved BGE’s conservation programs for implementation in 2012 through 2014. On December 23, 2014, the MDPSC approved BGE’s proposalfor 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’sEnergy 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 thismechanism, 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 differencebetween BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must secure fixed price contractsfor at least 10% but not more than 20% of forecasted system supply requirements for flowing (i.e. non-storage) gas for the November throughMarch 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 hasminimal impact on BGE’s gas revenue net of purchased power expense or financial position. At December 31, 2014, there were 40 competitivenatural gas suppliers serving BGE customers. At December 31, 2014, the number of retail customers purchasing fuel from a 28Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentscompetitive natural gas supplier was approximately 161,000 representing 25% of total retail customers. Retail deliveries purchased fromcompetitive 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 firmtransportation 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 tobe 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 dailycapacity 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 6mmcf, 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 sufficientvolumes of natural gas during the summer months for operations of its liquefied natural gas facility during peak winter periods. BGE historicallyhas been able to arrange short-term contracts or exchange agreements with other gas companies in the event of short-term disruptions to gassupplies 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 betweenshareholders 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 withthe MDPSC, ultimately requesting an increase of $68 million. On October 17, 2014, BGE filed with the MDPSC the Settlement Agreement reachedwith all parties to the case under which it would receive an increase of $38 million in gas base rates. The Settlement Agreement establishes newdepreciation rates which have the effect of increasing annual gas depreciation expense by approximately $2 million. On December 14, 2014, thePublic Utility Law Judge issued a proposed order approving the Settlement Agreement without modification, which became a final order onDecember 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 electrictransmission facilities to ensure the adequate capacity, reliability and efficiency of its system. BGE, as a transmission facilities owner, hasvarious construction commitments under PJM’s RTEP as discussed in BGE’s most recent estimate of capital expenditures for plant additions andimprovements for 2015 is approximately $700 million. 29Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSee 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 CapitalResources for further information. ComEd, PECO and BGE Transmission Services ComEd, PECO and BGE provide unbundled transmission service under rates approved by FERC. FERC has used its regulation oftransmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesalemarkets. Under FERC’s open access transmission policy promulgated in Order No. 888, ComEd, PECO and BGE, as owners of transmissionfacilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. ComEd, PECO and BGE arerequired to comply with FERC’s Standards of Conduct regulation governing the communication of non-public information between the transmissionowner’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 theadministrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM energy, capacity and other markets, and, throughcentral dispatch, controls the day-to-day operations of the bulk power system for the PJM region. ComEd, PECO and BGE are members of PJMand provide regional transmission service pursuant to the PJM Tariff. ComEd, PECO, BGE and the other transmission owners in PJM have turnedover control of their transmission facilities to PJM, and their transmission systems are currently under the dispatch control of PJM. Under the PJMTariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates basedon 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 theagreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formularate calculation on an annual basis. PECO default service customers are charged for retail transmission services through a rider designed to recover PECO’s PJM transmissionnetwork 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 customersand earns revenue as a transmission facility owner is a FERC-approved rate. This is the rate that all load serving entities in the PECOtransmission 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 theagreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formularate calculation on an annual basis. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regardingtransmission services. 30Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsEmployees As of December 31, 2014, Exelon and its subsidiaries had 28,993 employees in the following companies, of which 9,276 or 32% werecovered by collective bargaining agreements (CBAs): IBEW Local 15 IBEW Local 614 Other CBAs Total EmployeesCovered by CBAs TotalEmployees Generation 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 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’sseparate 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 MilePoint which will expire in 2020. Additionally, during 2014, Generation finalized CBAs with the Security Officer unions at Dresden, LaSalle, Limerick and Quad Cities, which expirebetween 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 other3-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 theSecurity 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 thefederal government and various state and local jurisdictions in which they operate their facilities. The Registrants are also subject to regulationsadministered by the U.S. EPA and various state and local environmental protection agencies. Federal, state and local regulation includes theauthority 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 toaddress environmental compliance and strategy, including the CEO; the Senior Vice President, Corporate Strategy and Chief SustainabilityOfficer; the Corporate Environmental Strategy Director and the Environmental Regulatory Strategy Director, as well as senior management ofGeneration, ComEd, PECO and BGE. Performance of those individuals directly involved in environmental compliance and strategy is reviewedand affects compensation as part of the annual individual performance review process. The Exelon Board has delegated to its corporategovernance committee authority to oversee Exelon’s compliance with laws and regulations and its strategies and efforts to protect and improve thequality of the environment, including Exelon’s climate change and sustainability policies and programs, as discussed in further detail below. TheExelon Board has also delegated to its Generation Oversight Committee authority to oversee environmental, health and safety issues relating toGeneration. The respective Boards of ComEd, PECO and BGE, which each include directors who also serve on the Exelon board, overseeenvironmental, health and safety issues related to ComEd, PECO and BGE. 31(a)(b)(c) (e) (d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAir 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 permitshave been obtained by Exelon’s subsidiaries and must be renewed periodically. The Clean Air Act establishes a comprehensive and complexnational program to reduce substantially air pollution from power plants. See ITEM 7.—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS foradditional information regarding clean air regulation in the forms of the CSAPR, the regulation of hazardous air pollutants from coal- and oil-firedelectric generating facilities under MATS, and regulation of GHG emissions, in addition to NOVs issued to Generation and ComEd for allegedviolations 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 stateenvironmental agency to which the permit program has been delegated and must be renewed periodically. Certain of Generation’s power generationfacilities discharge industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits orpending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction ofcertain other state and regional agencies and compacts, including the Delaware River Basin Commission and the Susquehanna River BasinCommission. Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect thebest technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All ofGeneration’s and CENG’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cyclerecirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. For Generation, those facilities areClinton, 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 beperformed to determine the best technology available, followed by an implementation period. The timing of the various requirements for eachfacility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this isleft 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 andentrainment of aquatic life at a facility’s cooling water intake structure. The rule provides the state permitting director with significant discretion todetermine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application ofa cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency mayrequire closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The rule also provides anumber of flexible compliance options to reduce impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by theinstallation of screens or other technology at the intake. A number of concerns raised by the electric generation industry about the proposed rulewere resolved favorably in the final rule. 32Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsUntil 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 futureresults of operations, cash flows capital expenditures, and financial position. Should a state permitting director determine that a facility must installcooling towers to comply with the rule, that facility’s economic viability would be called into question. However, the likely impact of the rule hasbeen significantly decreased since the final rule does not mandate cooling towers as a national standard, and the state permitting director isrequired 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 bestavailable technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as theperformance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not whollydisproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goalcannot 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 thecontinued operation of Salem with its existing cooling water system. NJDEP advised PSEG, in July 2004, that it strongly recommended reducingcooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewalof the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated thatthe continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meetthe Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permitrenewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling waterintake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s and Generation’s share of the total cost ofthe retrofit and any resulting interim replacement power would likely be in excess of $430 million, based on a 2006 estimate, and would result inincreased depreciation expense related to the retrofit investment. However, it is unknown at this time whether implementation of the final EPA rulewill 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 ofhazardous substances into the environment and authorizes the U.S. EPA either to clean up sites at which hazardous substances have createdactual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters ofhazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for thecleanup 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 toperform a cleanup, can be sued for costs associated with a U.S. EPA-directed cleanup, may voluntarily settle with the U.S. EPA concerning theirliability 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 wereconducted. 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 mayundertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party. 33Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSee Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional informationregarding 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 ICCorder, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recoverenvironmental remediation costs of the MGP sites through a provision within customer rates. While BGE does not have a rider for MGP clean-upcosts, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. The amount to be expended in2015 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 ofDecember 31, 2014, Generation has established an appropriate liability to comply with environmental remediation requirements includingcontamination attributable to low level radioactive residues at a storage and reprocessing facility named Latty Avenue, and at a disposal facilitynamed 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 forother environmental remediation costs. See Notes 3—Regulatory Matters and 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statementsfor 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 significantcontributor to the human-caused emissions of GHGs that many in the scientific community believe contribute to global climate change, and asreported by the Intergovernmental Panel on Climate Change in their Fifth Assessment Report Summary for Policy Makers issued in September2013. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear, hydroelectric, wind and solarphotovoltaic), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity. By virtue of itssignificant investment in low-carbon intensity assets, Generation’s emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unitof electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions, primarily at its fossil fuel-fired generatingplants; CO2, methane and nitrous oxide are all emitted in this process, with CO2 representing the largest portion of these GHG emissions. GHGemissions from combustion of fossil fuels represent the majority of Exelon’s direct GHG emissions in 2014, although only a small portion ofExelon’s electric supply is from fossil generating plants. Other GHG emission sources at Exelon include natural gas (methane) leakage on thenatural gas systems, sulfur hexafluoride (SF6) leakage in its electric transmission and distribution operations and refrigerant leakage from itschilling and cooling equipment as well as fossil fuel combustion in its motor vehicles and usage of electricity at its facilities. Despite its focus onlow-carbon generation, Exelon believes its operations could be significantly affected by the possible physical risks of climate change and bymandatory programs to reduce GHG emissions. See ITEM 1A. RISK FACTORS for information regarding the market and financial, regulatory andlegislative, and operational risks associated with climate change. 34Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsClimate Change Regulation. Exelon is, or may become, subject to climate change regulation or legislation at the Federal, regional andstate 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 KyotoProtocol now requires participating developed countries to cap GHG emissions at certain levels until 2020, when the new global agreement onemissions reduction is scheduled to become effective. This new global agreement for GHG emissions reductions was agreed to only in conceptduring 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 forformally setting global target in 2015. At COP 20 held in Lima, Peru, in December 2014, participating countries outlined the universal GHGreduction agreement to be finalized in 2015 at COP 21 in Paris. On November 11, 2014, President Obama and President Xi Jinping of China jointlyannounced their respective “intended nationally determined contributions” for post 2020 greenhouse gas emission reductions. The US announcednet greenhouse gas emission reductions of 26-28 percent below 2005 levels by 2025, while China announced targets to peak CO emissionsaround 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 overone–third of global greenhouse gas emissions. Federal Climate Change Legislation and Regulation. Various stakeholders, including Exelon, legislators and regulators, shareholders andnon-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 beenacted. If such legislation is adopted, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procureemission allowances or credits. In June 2013, the White House released the President’s Climate Action Plan which consists of a wide variety ofexecutive actions targeting GHG reductions, preparing for the impacts of climate change and showing leadership internationally; but the plan didnot directly trigger any new requirements or legislative action. The U.S. EPA is addressing the issue of carbon dioxide (CO) emissions regulation for new and existing electric generating units through theNew Source Performance Standards (NSPS) under Section 111 of the Clean Air Act. Pursuant to President Obama’s June 25, 2013 memorandumto 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 compliancefor CO emissions for new fossil-fuel electric generating units, particularly coal-fired units. Under the President’s memorandum, the U.S. EPA wasalso required to propose a Section 111(d) rule no later than June 1, 2014 to establish CO emission regulations for existing stationary sources. Thesecond rulemaking, under Section 111(d) of the Clean Air Act, focuses on modified, reconstructed and existing fossil power plants. The proposedrule was published in the Federal Register on June 18, 2014, and the public comment period closed on December 1, 2014. The Climate ActionPlan 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 laterthan June 30, 2016. Regional and State Climate Change Legislation and Regulation. After a two-year program review, the nine northeast and mid-Atlantic statescurrently participating in the Regional Greenhouse Gas Reduction Initiative (RGGI) released an updated RGGI Model Rule and Program ReviewRecommendations Summary on February 7, 2013. Under the updated RGGI program the regional RGGI CO 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 thenew program are provisions for cost containment reserve (CCR) allowances, which will become available if the total demand for allowances, abovethe CCR trigger price, exceeds the number of CO allowances 35222222Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsavailable 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 increasesby 2.5 percent each year). Such an outcome could put modest upward pressure on wholesale power prices; however, the specifics are currentlyuncertain. At the state level, the Illinois Climate Change Advisory Group, created by Executive Order 2006-11 on October 5, 2006, made its finalrecommendations on September 6, 2007 to meet the Governor’s GHG reduction goals. At this time, the only requirements imposed by the state ofIllinois 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 reductionin GHG emissions by 2020. The Climate Change Advisory Committee continues to meet quarterly to review Climate Action Work Plans for theresidential, commercial and industrial sectors. The Climate Change Action Plan does not impose any requirements on Generation or PECO at thistime. The Maryland Commission on Climate Change was chartered in 2007 and released a 42 greenhouse gas reduction strategy, climate actionplan, on August 27, 2008. The plan’s primary policy recommendation to formally adopt science-based regulatory goals to reduce Maryland’s GHGemissions, was realized with the passage of the Greenhouse Gas Emissions Reduction Act of 2009 (GGRA) which requires Maryland to reduce itsGHG emissions by 25 percent below 2006 levels by 2020. It also directed the Maryland Department of Environment to prepare and implement anaction 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 advocatedraising the renewable portfolio standard requirement from 20% by 2022 to 25% by 2022. The Department of Environment is required to submit aDecember 2015 report to the Governor and General Assembly on progress towards the 25% mandate; its costs and benefits; the need for targetadjustments; and the status of federal programs. In 2016, the Legislature will review the progress report, its economic impacts on manufacturingsector 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 reduceGHG, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon remains one of the largest, lowest carbonelectric generators in the United States: nuclear for base load, natural gas for marginal and peak demand, hydro and pumped storage, andsupplemental wind and solar renewables. As further legislation and regulation imposing requirements on emissions of GHG and air pollutants arepromulgated, Exelon’s low-carbon, low-emission generation fleet will position the company to benefit from its comparative advantage over othergeneration fleets. Based on an independent third-party verification of Exelon’s GHG performance through year-end 2013, it achieved the Exelon 2020 goal ofabating 17.5 million tonnes of GHG emissions annually, seven years ahead of plan. Exelon’s approach for addressing the issue of climate changeis currently focused on continuing to manage its GHG emissions from internal operations, contributing to reducing overall grid GHG emissions andensuring 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 lawsspecifically addressing energy efficiency and renewable energy initiatives. In addition to state level activity, RPS legislation has been consideredand may be considered again in the future by the United States Congress. Also, states that currently do not have RPS requirements may adoptsuch legislation in the future. 36Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIllinois utilities are required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricitythat each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that willcumulatively 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 aresubject to rate impact criteria set forth by Illinois legislation. As of December 31, 2014, ComEd had purchased sufficient renewable energyresources 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 Mattersof 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 futurecommitments 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 electricenergy 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% beginningJune 1, 2014 and continuing through May 31, 2015. PECO was also required to supply 6.2% of electric energy generated from Tier II (includingwaste coal, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing wood and by-products ofthe 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 complywith these requirements, PECO entered into agreements with varying terms with accepted bidders, including Generation, to purchase non-solarTier 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 Marylandby 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 thanpump storage generation, and waste-to-energy). The RPS requirement began in 2006, requiring that suppliers procure 1.0% and 2.5% from Tier 1and 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 ofTier 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 useof alternative energy resources; however, the wholesale suppliers that supply power to BGE through SOS procurement auctions have theobligation, 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 thestates in which it does business from renewable resources or approved equivalents such as RECs. Potential regulation and legislation regardingrenewable 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 thesame 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 FinancialStatements for additional information. 37Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExecutive Officers of the Registrants as of February 13, 2015 Exelon Name Age Position PeriodCrane, 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 - 2010Cornew, 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 - 2012O’Brien, Denis P. 54 Senior Executive Vice President, Exelon; Chief Executive Officer, ExelonUtilities 2012 - Present Vice Chairman, ComEd, PECO, BGE 2012 - Present Chief Executive Officer, PECO; Executive Vice President, Exelon 2007 - 2012 President and Director, PECO 2003 - 2012Pramaggiore, Anne R. 56 Chief Executive Officer, ComEd 2012 - Present President, ComEd 2009 - Present Chief Operating Officer, ComEd 2009 - 2012Adams, Craig L. 62 President and Chief Executive Officer, PECO 2012 - Present Senior Vice President and Chief Operating Officer, PECO 2007 - 2012Butler, 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 - 2010Von Hoene Jr., William A. 61 Senior Executive Vice President and Chief Strategy Officer, Exelon 2012 - Present Executive Vice President, Finance and Legal, Exelon 2009 - 2012Thayer, Jonathan W. 43 Senior Executive Vice President and Chief Financial Officer, Exelon 2012 - Present Senior Vice President and Chief Financial Officer, Constellation Energy;Treasurer, Constellation Energy 2008 - 2012Aliabadi, 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 - 2011DesParte, Duane M. 51 Senior Vice President and Corporate Controller, Exelon 2008 - Present 38 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration Name Age Position PeriodCornew, 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 - 2012Nigro, 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 - 2012Pacilio, 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 - 2010Hanson, 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 - 2010DeGregorio, 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 - 2010Wright, 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 - 2012Aiken, Robert 48 Vice President and Controller, Generation 2012 - Present Executive Director and Assistant Controller, Constellation 2011 - 2012 Executive Director of Operational Accounting, Constellation EnergyCommodities Group 2009 - 2011 39Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsComEd Name Age Position PeriodPramaggiore, Anne R. 56 Chief Executive Officer, ComEd 2012 - Present President, ComEd 2009 - Present Chief Operating Officer, ComEd 2009 - 2012Donnelly, Terence R. 54 Executive Vice President and Chief Operating Officer, ComEd 2012 - Present Executive Vice President, Operations, ComEd 2009 - 2012Trpik Jr., Joseph R. 45 Senior Vice President, Chief Financial Officer and Treasurer, ComEd 2009 - PresentJensen, Val 59 Senior Vice President, Customer Operations, ComEd 2012 - Present Vice President, Marketing and Environmental Programs, ComEd 2008 - 2012O’Neill, Thomas S. 52 Senior Vice President, Regulatory and Energy Policy and General Counsel,ComEd 2010 - Present Senior Vice President, Exelon 2009 - 2010Marquez Jr., Fidel 53 Senior Vice President, Governmental and External Affairs, ComEd 2012 - Present Senior Vice President, Customer Operations, ComEd 2009 - 2012Brookins, 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 - 2010Anthony, J. Tyler 50 Senior Vice President, Distribution Operations, ComEd 2010 - Present Vice President, Transmission and Substations, ComEd 2007 - 2010Kozel, 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 PeriodAdams, Craig L. 62 President and Chief Executive Officer, PECO 2012 - Present Senior Vice President and Chief Operating Officer, PECO 2007 - 2012Barnett, Phillip S. 51 Senior Vice President and Chief Financial Officer, PECO 2007 - Present Treasurer, PECO 2012 - PresentInnocenzo, Michael A. 49 Senior Vice President and Chief Operations Officer, PECO 2012 - Present Vice President, Distribution System Operations and Smart Grid/SmartMeter, PECO 2010 - 2012 Vice President, Distribution System Operations 2007 - 2010 40Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsName Age Position PeriodWebster Jr., Richard G. 53 Vice President, Regulatory Policy and Strategy, PECO 2012 - Present Director of Rates and Regulatory Affairs 2007 - 2012Murphy, Elizabeth A. 55 Vice President, Governmental and External Affairs, PECO 2012 - Present Director, Governmental & External Affairs, PECO 2007 - 2012Jiruska, Frank J. 54 Vice President, Customer Operations, PECO 2013 - Present Director of Energy and Marketing Services, PECO 2010 - 2013Diaz Jr., Romulo L. 68 Vice President and General Counsel, PECO 2012 - Present Vice President, Governmental and External Affairs, PECO 2009 - 2012Bailey, 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 PeriodButler, 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 - 2010Woerner, 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 - 2010Vahos, 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 - 2010Case, Mark D. 53 Vice President, Strategy and Regulatory Affairs, BGE 2012 - Present Senior Vice President, Strategy and Regulatory Affairs, BGE 2007 - 2012Biagiotti, 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 41Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsName Age Position PeriodGahagan, Daniel P. 61 Vice President and General Counsel, BGE 2007 - PresentBauer, 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 ChiefFinancial 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 thatRegistrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the RMC, which comprises officers of theRegistrants, to identify and evaluate the most significant risks of the Registrants’ businesses, and the appropriate steps to manage and mitigatethose risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the finance and risk committee and auditcommittee of the Exelon board of directors and the ComEd, PECO and BGE boards of directors. In addition, the generation oversight committee ofthe Exelon board of directors evaluates risks related to the generation business. The risk factors discussed below may adversely affect one ormore of the Registrants’ results of operations and cash flows and the market prices of their publicly traded securities. Each of the Registrants hasdisclosed the known material risks that affect its business at this time. However, there may be further risks and uncertainties that are notpresently known or that are not currently believed by a Registrant to be material that may adversely affect its performance or financial condition inthe future. Exelon’s financial condition and results of operations are affected to a significant degree by: (1) Generation’s position as a predominantlynuclear generator selling power into competitive energy markets with a concentration in select regions, and (2) the role of ComEd, PECO and BGEas operators of electric transmission and distribution systems in three of the largest metropolitan areas in the United States. Factors that affectthe financial condition and results of operations of the Registrants fall primarily under the following categories, all of which are discussed in furtherdetail 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 theprice of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of othergeneration resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where theRegistrants 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 lawsand regulations that govern competitive markets and utility cost recovery, and that drive environmental policy. In particular, Exelon’s andGeneration’s financial performance may be affected by changes in the design of competitive wholesale power markets or Generation’sability to sell power in those markets. In addition, potential regulation and legislation, including legislation or regulation regarding climatechange and renewable portfolio standards, could have significant effects on the Registrants. Also, returns for ComEd, PECO and BGEare influenced significantly by state regulation and regulatory proceedings. 42Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents • Operational Factors. The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet ofnuclear power reactors and large electric and gas distribution systems. The safe and effective operation of the nuclear facilities and theability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability andsafety of its energy delivery systems are fundamental to Exelon’s ability to protect and grow shareholder value. Additionally, theoperating costs of ComEd, PECO and BGE, and the opinions of their customers and regulators, are affected by those companies’ abilityto 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 agreementannounced 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 ofoperations 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 earningsand 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 ofelectricity 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 theelectricity unit. Often, the next unit of electricity will be supplied from generating stations fueled by fossil fuels. Consequently, changes in themarket price of fossil fuels often result in comparable changes to the market price of power. For example, the use of new technologies to recovernatural 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 throughRPS or otherwise subsidized or encouraged through climate legislation or regulation, may displace a higher marginal cost plant, further reducingpower prices. In addition, further delay or elimination of EPA air quality regulations could prolong the duration for which the cost of pollution fromfossil 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 ofelectricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs caneach depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on electricitymarket prices. The tepid economic environment in recent years and growing energy efficiency and demand response initiatives have limited thedemand for electricity in Generation’s markets. In addition, in some markets, the supply of electricity through wind or solar generation, whencombined with other base-load generation such as nuclear, may often exceed demand during some hours of the day, resulting in loss of revenuefor base-load generating plants. The risk of increased supply in excess of demand is heightened by continued or increased RPS mandates or othersubsidies, including ITCs and PTCs. Retail Competition: Generation’s retail operations compete for customers in a competitive environment, which affects the margins thatGeneration 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 43Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentswholesale generators (including Generation) use their retail operations to hedge generation output. Increased or more aggressive competition canadversely 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 operationsand cash flows, and such impacts could be emphasized given Generation’s concentration of base-load electric generating capacity within primarilytwo geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s abilityto fund other discretionary uses of cash such as growth projects or to pay dividends. In addition, such conditions may no longer support thecontinued operation of certain generating facilities, which could adversely affect Exelon’s and Generation’s results of operations through increaseddepreciation rates, impairment charges and accelerated future decommissioning costs which may be offset in whole or in part by reducedoperating and maintenance expenses. A slow recovery in market conditions could result in a prolonged depression of or further decline incommodity prices, including low forward natural gas and power prices and low market volatility, which could also adversely affect Exelon’s andGeneration’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 maynegatively 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 topurchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterpartiesto these arrangements fail to perform, Generation might be forced to purchase or sell energy or fuel in the wholesale markets at less favorableprices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposedto risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs, the purpose of which is to spreadsuch risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced ratingdowngrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and naturalgas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk resultswhen customers default on their contractual obligations. This risk represents the loss that may be incurred due to the nonpayment of a customer’saccount 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 andprocedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affectGeneration’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect onmarket stability. The Registrants are potentially affected by emerging technologies that may over time affect or transform the energy industry, includingtechnologies 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 energytechnologies, broad consumer adoption of electric vehicles and energy storage devices. Such developments could affect the price of energy, couldaffect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distributionsystems to address changing load demands and could make portions 44Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsof our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologiescould also result in further declines in commodity prices or demand for delivered energy. Each of these factors could materially affect theRegistrants’ results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operatingand maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation anddecommissioning 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 therelated employee benefit plan obligations, which then could require significant additional funding. (Exelon, Generation, ComEd, PECOand BGE) Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy may adverselyaffect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significantobligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values aresubject to market fluctuations and will yield uncertain returns, which may fall below the Registrants’ projected return rates. A decline in the marketvalue of the NDT fund investments may increase Generation’s funding requirements to decommission its nuclear plants. A decline in the marketvalue 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 liabilitiesincrease, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements orchanges in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements may also increase the costs andfunding requirements of the obligations related to the pension and OPEB plans. If future increases in pension and other postretirement costs as aresult of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from ComEd, PECO and BGEcustomers, the results of operations and financial positions of ComEd, PECO and BGE could be negatively affected. Ultimately, if the Registrantsare 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 inseveral ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-termcommitments, 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, tomeet 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 capitalmarkets or draw on their respective bank revolving credit facilities. The Registrants’ access to funds under their credit facilities is dependent onthe ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their fundingcommitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requestsfrom the Registrants and other borrowers within a short period of time. The inability to access capital markets or credit facilities, and longer termdisruptions in the capital and credit markets as a result of uncertainty, changing or increased 45Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsregulation, 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 otherdiscretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe. Disruptions in the European markets couldreduce 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 toprovide financing for the proposed PHI acquisition. The credit facilities include $8.5 billion in aggregate total commitments of which $7.3 billion wasavailable as of December 31, 2014. There were no borrowings under the Registrants’ credit facilities as of December 31, 2014. See Note 13—Debtand 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 beadversely affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that may affect participants incommodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminishthe liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses inthe competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace marketstructures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverseeffect 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 thecredit standards in its agreements with its trading counterparties, it would be required to provide significant amounts of collateral underits 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. IfGeneration were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfythe credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters ofcredit or cash, which may have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at anypoint in time is dependent on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty andrelated agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higherborrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludesthat the level of business or financial risk and overall creditworthiness of the power generation industry in general, or Generation in particular, hasdeteriorated. 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 collateralprovisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and ComEd, PECO andBGE were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateralin the forms of letters of credit or cash, which may have a material 46Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsadverse 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 marketprices fall and decrease as forward market prices rise. Given the relationship to forward market prices, contract collateral requirements can bevolatile. 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 businessor 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, becomeless 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 weakeroperating performance or due to a failure to properly manage their capital structure. In addition, changes in ratings methodologies by the agenciescould 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 andprocedures intended to assure that ComEd, PECO and BGE are treated as separate, independent companies, distinct from Exelon and otherExelon subsidiaries in order to isolate ComEd, PECO and BGE from Exelon and other Exelon subsidiaries in the event of financial difficulty atExelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) may help avoid or limit a downgrade in the creditratings of ComEd, PECO and BGE in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratingsof ComEd, PECO or BGE could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating ofExelon 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 orBGE 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 impactsof 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 theprocurement 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 fabricationservices. Coal, natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply marketsfor nuclear fuel, coal, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that may negativelyaffect 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 andGeneration) Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities exposeGeneration to risks of commodity price movements. Generation attempts to manage this exposure through enforcement of established risk limitsand risk management procedures. These risk limits and risk management procedures may not work as planned 47Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsand cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made basedon projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying thosedecisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficultto predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict theimpact that its commodity trading activities and risk management decisions may have on its business, operating results, cash flows or financialposition. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions inGeneration’s power generation portfolio. The proportion of hedged positions in its power generation portfolio may cause volatility in Generation’sfuture 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 andother customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale powermarkets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generationmust purchase power in the wholesale power markets. Generation’s financial results may be negatively affected if it is unable to cost-effectivelymeet 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 taxeffects 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 taxrules applicable to U.S. domiciled corporations. Exelon cannot assess what the overall effect of such potential legislation might be on its results ofoperations and cash flows. 1999 sale of fossil generating assets. The IRS has challenged Exelon’s 1999 tax position on its like-kind exchange transaction. Exelonand 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 inthe 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 exchangeposition. 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 whichapproximately $310 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless. In addition toattempting to impose tax on the like-kind exchange position, the IRS has asserted penalties for a substantial understatement of tax, which couldresult 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. Thetiming effects of the final resolution of the like-kind exchange matter are unknown. See Note 14—Income Taxes of the Combined Notes toConsolidated Financial Statements for additional information. 48Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTax reserves and the recoverability of deferred tax assets. The Registrants are required to make judgments in order to estimate theirobligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoingappeals issues related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that havebeen taken that may be subject to challenge by the tax authorities. The Registrants also estimate their ability to utilize tax benefits, includingthose in the form of carryforwards and tax credits. See Notes 1—Significant Accounting Policies and Note 14—Income Taxes of the CombinedNotes 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 tocustomers recover BGE’s wholesale power supply costs and include a return component. For PECO, purchased natural gas costs are charged tocustomers with no return or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism thatcompares the actual cost of gas to a market index. The difference between the actual cost and the market index is shared equally betweenshareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higherrates related to purchased power and natural gas can result in declines in customer usage, lower revenues and potentially additional uncollectibleaccounts expense for ComEd, PECO and BGE. In addition, any challenges by the regulators or ComEd, PECO and BGE as to the recoverabilityof these costs could have a material effect on the Registrants’ results of operations and cash flows. Also, ComEd’s, PECO’s and BGE’s cashflows can be affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery fromcustomers. Further, the impacts of economic downturns on ComEd, PECO and BGE customers and purchased natural gas costs for PECO and BGEcustomers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrialcustomers, and the related regulatory limitations on residential service terminations, may result in an increase in the number of uncollectiblecustomer balances, which would negatively impact ComEd’s, PECO’s and BGE’s results from operations and cash flows. Generation’s customersupply activities face economic downturn risks similar to Exelon’s utility businesses, such as lower volumes sold and increased expense foruncollectible customer balances. As Generation increases its customer supply footprint, economic downturn impacts could negatively affectGeneration’s results from operations and cash flows. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKETRISK 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 temperaturesbelow normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Weather conditions directly influencethe demand for electricity and natural gas and affect the price of energy commodities. Moderate temperatures adversely affect the usage of energyand resulting revenues at ComEd and PECO. Due to revenue decoupling, BGE recognizes revenues at MDPSC-approved levels per customer,regardless of what 49Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsactual distribution volumes are for a billing period, and is not affected by actual weather with the exception of major storms. Extreme weatherconditions or damage resulting from storms may stress ComEd’s, PECO’s and BGE’s transmission and distribution systems, communicationsystems and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customerdemand. These extreme conditions may have detrimental effects on ComEd’s, PECO’s and BGE’s results of operations and cash flows. First andthird 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 thatweather is warmer in the summer or colder in the winter than assumed, Generation may require greater resources to meet its contractualcommitments. Extreme weather conditions or storms may affect the availability of generation and its transmission, limiting Generation’s ability tosource or send power to where it is sold. In addition, drought-like conditions limiting water usage can impact Generation’s ability to run certaingenerating assets at full capacity. These conditions, which cannot be accurately predicted, may have an adverse effect by causing Generation toseek 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, whichwould 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 assetsaccount 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 onExelon’s unamortized energy contracts. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and usedwhenever events or circumstances indicating a potential impairment exist. Factors such as the business climate, including current and futureenergy and market conditions, environmental regulation, and the condition of assets are considered when evaluating long-lived assets for potentialimpairment. An impairment would require the Registrants to reduce the carrying value of the long-lived asset through a non-cash charge toexpense 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 directfinancing lease investments. The investments represent the estimated residual value of the leased assets at the end of the lease term. On anannual basis, Exelon reviews the estimated residual values of its direct financing lease investments and records a non-cash impairment charge toexpense if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. Such animpairment 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 PECOand Unicom Corporation, the former parent company of ComEd. Under GAAP, goodwill remains at its recorded amount unless it is determined tobe impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to its carrying value. If animpairment occurs, the amount of the impaired goodwill will be written-off to expense, which will also reduce equity. The actual timing and amountsof any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. A successful IRS challenge to 50Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon’s and ComEd’s like-kind exchange income tax position, adverse regulatory actions such as early termination of EIMA, or changes insignificant assumptions used in estimating ComEd’s fair value (e.g., discount and growth rates, utility sector market performance andtransactions, operating and capital expenditure requirements and the fair value of debt) could result in an impairment. Such an impairment wouldresult 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—CriticalAccounting 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 goodwillimpairments. The Registrants’ businesses are capital intensive, and their assets may require significant expenditures to maintain and are subject tooperational 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 byComEd, PECO and BGE in transmission and distribution infrastructure projects. These operational systems and infrastructure have been inservice for many years. Older equipment, even if maintained in accordance with good utility practices, is subject to operational failure, includingevents that are beyond the Registrants’ control, and may require significant expenditures to operate efficiently. The Registrants’ results ofoperations, financial condition, or cash flows could be adversely affected if they were unable to effectively manage their capital projects or raisethe necessary capital. Furthermore, operational failure of electric or gas systems or infrastructure could result in potential liability if such failureresults in damage to property or injury to individuals. See ITEM 1. BUSINESS for further information regarding the Registrants’ potential futurecapital 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 theRegistrants for various obligations, and the Registrants may incur substantial costs in the event that the applicable Registrant is unableto 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 theirsubsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, the Registrantscould incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on theoperating 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 andhold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in theircreditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for theobligations, which could impact that Registrant’s results of operations, cash flows and financial position. In connection with Exelon’s 2001corporate restructuring, Generation assumed certain of ComEd’s and PECO’s rights and obligations with respect to their former generationbusinesses. Further, ComEd and PECO may have entered into agreements with third parties under which the third-party agreed to indemnifyComEd or PECO for certain obligations related to their respective former generation businesses that have been assumed by Generation as part ofthe 51Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsrestructuring. If the third-party or Generation experienced events that reduced its creditworthiness or the indemnity arrangement becameunenforceable, 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 electricgeneration supplier for their energy needs, planning to meet Generation’s obligation to provide the supply needed to serve Generation’s share of anelectric distribution company’s default service obligation is more difficult than planning for retail load before the advent of retail competition. Beforeretail competition, the primary variables affecting projections of load were weather and the economy. With retail competition, another major factoris retail customers switching to or from competitive electric generation suppliers. If fewer of such customers switch from its retail load servingcounterparties than Generation anticipates, the load that Generation must serve will be greater than anticipated, which could, if market prices haveincreased, increase Generation’s costs (due to its need to go to market to cover its incremental supply obligation) more than the increase inGeneration’s revenues. If more customers from its retail load serving counterparties switch than Generation anticipates, the load that Generationmust 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 andlegislative 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 cashflows are heavily dependent on the ability of ComEd, PECO and BGE to recover their costs for the retail purchase and distribution of power to theircustomers. Similarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability toengage in certain transactions. In the planning and management of operations, the Registrants must address the effects of regulation on theirbusinesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemakingagencies and taxing authorities. Additionally, the Registrants need to be cognizant of rules changes or Registrant actions that could result inpotential violation of tariffs, market rules and anti-manipulation laws. Fundamental changes in regulations or other adverse legislative actionsaffecting the Registrants’ businesses would require changes in their business planning models and operations and could adversely affect theirresults 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 resultsof operations, cash flows and financial positions. Various legislative and regulatory proposals to address climate change through GHG emissionreductions, if enacted, could result in increased costs to entities that generate electricity through carbon-emitting fossil fuels, which could increasethe market price at which all generators in a region, including Generation, may sell their output, thereby increasing the revenue Generation couldrealize from its low-carbon nuclear assets. However, national regulation or legislation addressing climate change through 52Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsan RPS could also increase the pace of development of wind energy facilities in the Midwest, which could put downward pressure on wholesalemarket prices for electricity from Generation’s Midwest nuclear assets, partially offsetting any additional value Exelon and Generation might derivefrom Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future. Similarly, final regulations underSection 111(d) of the Clean Air Act may not provide sufficient incentives for states to utilize carbon-free nuclear power as a means of meetinggreenhouse gas emission reduction requirements, while continuing a policy of favoring renewable energy sources. Current state level climatechange and renewable regulation is already providing incentives for regional wind development. The Registrants cannot predict when or whetherany 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 andfunctioning 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-termcontracts, are located in the area encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherenceto and support for, policies that favor the preservation of competitive wholesale power markets, such as PJM’s, and (2) the absence of materialchanges to market structures that would limit or otherwise negatively affect market competitiveness. Generation could also be adversely affectedby 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 Note3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details related to the New Jersey CapacityLegislation 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 satisfyingFERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s authorityto sell at market-based rates and none denying that authority. As of December 31, 2014, Generation has submitted its triennial application seekingreauthorization 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 toExelon is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires thecreation of a new regulatory regime for over-the-counter swaps (Swaps), including mandatory clearing for certain categories of Swaps, incentivesto shift Swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. For nonsecurity-based Swaps including commodity Swaps, Dodd-Frank empowers the Commodity Futures Trading Commission (CFTC) to promulgateregulations implementing the law’s objectives. The primary aim of Dodd-Frank is to regulate the key intermediaries in the Swaps market, whichentities are either swap dealers (SDs), major swap participants (MSPs), and certain other financial entities, but the law also applies to a lesser 53Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsdegree to end-users of Swaps. On January 12, 2015, President Obama signed into law a bill that exempts from margin requirements Swaps usedby end-users to hedge or mitigate commercial risk. Moreover, the CFTC’s Dodd-Frank regulations preserve the ability of end users in the energyindustry to hedge their risks using Swaps without being subject to mandatory clearing, and excepts or exempts end-users from many of the othersubstantive regulations. Accordingly, as an end-user, Generation is conducting its commercial business in a manner that does not requireregistration 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 SDor 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 inaddition to certain international regulatory requirements still under development and that are similar to Dodd-Frank, Generation’s Swapcounterparties could be subject to additional and potentially significant capitalization requirements. These regulations could motivate the SDs andMSPs 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, ifany, 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, atthis 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 physicalasset base within the ComEd, PECO and BGE service territories, could increase Generation’s cost of doing business to the extent futurecomplaints or challenges regarding ComEd, PECO and/or BGE retail rates result in settlements or legislative or regulatory requirementsfunded 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 ofthem. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators andadvocacy 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 costsand transactions incurred by ComEd, PECO, or BGE, with Generation, irrespective of any previous regulatory processes or approvals underlyingthose transactions. The prospect of such challenges may increase the time, complexity and cost of the associated regulatory proceedings, andthe occurrence of such challenges may subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. Inaddition, government officials and legislators may seek ways to force Generation to contribute to efforts to mitigate potential or actual rateincreases, 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 Federalauthorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expendituresincluding how they 54Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentshandle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements can subject the Registrants toenforcement 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. Inaddition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now orformerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred andexpect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGPoperations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number ofproceedings 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 aquaticorganisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, thisdevelopment could result in material costs of compliance. Pursuant to discussions with the NJDEP regarding the application of Section 316(b) toOyster Creek, Generation agreed to permanently cease generation operations at Oyster Creek by December 31, 2019, ten years before theexpiration of its operating license in 2029. Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly ownedgeneration facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for allegedasbestos-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 forenvironmental matters related to the transferred property. If the transferee is unable, or fails, to discharge the assumed liability, a regulatoryauthority or injured person could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee may be limited bythe financial resources of the transferee. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated FinancialStatements for additional information. Changes in ComEd’s, PECO’s and BGE’s respective terms and conditions of service, including their respective rates, are subject toregulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which leadto uncertainty as to the ultimate result and which may introduce time delays in effectuating rate changes. (Exelon, ComEd, PECO andBGE) ComEd, PECO and BGE are required to engage in regulatory approval proceedings as a part of the process of establishing the terms andrates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumeradvocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases oreven reducing rates. The proceedings generally have timelines that may not be limited by statute. Decisions are subject to appeal, potentiallyleading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that ratesultimately approved by the applicable regulatory body may not be sufficient for ComEd, PECO or BGE to recover its costs by the time the ratesbecome effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates canbe adjusted, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smartgrid infrastructure, and energy efficiency and demand response programs. 55Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIn certain instances, ComEd, PECO and BGE may agree to negotiated settlements related to various rate matters, customer initiatives orfranchise 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 orFederal regulators in establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered orwhat rates of return will be allowed. Nevertheless, the expectation is that ComEd, PECO and BGE will continue to be obligated to deliver electricityto customers in their respective service territories and will also retain significant POLR and default service obligations to provide electricity andnatural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome andtiming of regulatory rate proceedings have a significant effect on the ability of ComEd, PECO and BGE, as applicable, to recover their costs andcould 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 negativelyaffect 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 isnot 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 newtechnologies, 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 consumptionresulting 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 materialto 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 thecriteria of the authoritative guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separableportion of their businesses no longer meets the criteria, Exelon, ComEd, PECO and BGE would be required to eliminate the financial statementeffects of regulation for that part of their business. That action would include the elimination of any or all regulatory assets and liabilities that hadbeen recorded in their Consolidated Balance Sheets and the recognition of a one-time charge in their Consolidated Statements of Operations. Theimpact 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 theelimination of ComEd’s, PECO’s and BGE’s regulatory assets and liabilities, respectively. 56Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFurther, Exelon would record a charge against OCI (before taxes) of up to $2.6 billion and $663 million for ComEd and BGE, respectively, relatedto 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 andresolution of the above items could lead to an additional impairment of ComEd’s goodwill, which could be significant and at least partially offset thegain at ComEd discussed above. A significant decrease in equity as a result of any changes could limit the ability of ComEd, PECO and BGE topay dividends under Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in futureresults of operations. See Notes 1—Significant Accounting Policies, 3—Regulatory Matters and 10—Intangible Assets of the Combined Notes toConsolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’sgoodwill, respectively. Exelon and Generation may incur material costs of compliance if Federal and/or state regulation or legislation is adopted to addressclimate change. (Exelon and Generation) Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies inmany business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. In 2009, selectNortheast 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 fromnew fossil plants that could potentially impact existing plants. If carbon reduction regulation or legislation becomes effective, Exelon andGeneration 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 RPScould increase the cost of compliance by mandating the purchase or construction of more expensive supply alternatives. For more informationregarding climate change, see ITEM 1. BUSINESS “Global Climate Change” and Note 22—Commitments and Contingencies of the CombinedNotes to Consolidated Financial Statements. The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likelyexposure 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 gasdistribution systems, PECO and BGE are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standardsare based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and marketinterface principles. Compliance with or changes in the reliability standards may subject the Registrants to higher operating costs and/or increasedcapital 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 remediationcosts 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 transmissionowners regarding assessments of transmission lines. The results of these assessments may require ComEd, PECO and BGE to incur incrementalcapital or 57Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsoperating and maintenance expenditures to ensure their transmission lines meet NERC standards. Uncertainties exist as to the construction ofnew transmission facilities, their cost and how those costs will be allocated to transmission system participants and customers. In accordancewith a FERC order and related settlement, PJM’s RTEP requires the costs of new transmission facilities to be allocated across the entire PJMfootprint 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 beneficiariesof the new facilities. Following a remand from the U.S. Court of Appeals for the Seventh Circuit, FERC reaffirmed its decision related to allocationof 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 kVand 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 footprintand 50% allocated to identified beneficiaries. Costs for all other facilities will be allocated to all identified beneficiaries. This later decision issubject to rehearing by FERC and possible appeal. See Note 3—Regulatory Matters and Note 22—Commitments and Contingencies of the Combined Notes to Consolidated FinancialStatements for additional information. The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination couldhave a material adverse effect on their results of operations, financial positions and cash flows. (Exelon, Generation, ComEd, PECO andBGE) The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of whichare summarized in Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes inthese 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 andprofitability 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 capitalexpenditures or may result in increased operating or decommissioning costs and significantly affect Generation’s results of operations or financialposition. 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 FukushimaDaiichi accident, the NRC’s focus on seismic risk intensified. As part of the NRC Near-Term Task Force (Task Force) review and evaluation of theFukushima Daiichi accident, the Task Force recommended that plant operators conduct seismic reevaluations. In January 2012, the NRC releasedan updated seismic risk model that plant operators must use in performing the seismic reevaluations recommended by the Task Force. Thesereevaluations 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 YuccaMountain, Nevada, and the timing of such facility opening, will 58Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentssignificantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for thesecosts. The NRC’s temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spentnuclear fuel at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants. In June 2012, theUnited States Court of Appeals for the DC Circuit vacated the NRC’s temporary storage rule on the grounds that the NRC should have conducted amore comprehensive environmental review to support the rule. On September 19, 2014, the NRC issued a revised rule codifying the NRC’s genericdeterminations regarding the environmental impacts of continued storage of spent nuclear fuel beyond a reactor’s licensed operating life. TheContinued 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 decommissionfully its nuclear units. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE afee 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 ofColumbia Circuit ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is aviable 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 DOEnotified 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, Exelonand Generation will not accrue any further costs related to SNF disposal fees. Generation currently estimates 2025 to be the earliest date when theDOE will begin accepting SNF, which could be delayed by further regulatory action. See Note 22—Commitments and Contingencies of theCombined Notes to Consolidated Financial Statements for additional information on the spent nuclear fuel obligation. Generation cannot predictwhat, 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 andcash flows. License renewals. Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of anyrenewed license period. If the NRC does not renew the operating licenses for Generation’s nuclear stations or a station cannot be operated throughthe end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates, impairmentcharges and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently includeassumptions that license renewal will be received. In addition, Generation may lose revenue and incur increased fuel and purchased powerexpense 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 theenergy 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, potentiallydangerous 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. 59Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsNatural disasters, war, acts and threats of terrorism, pandemic and other significant events may adversely affect Exelon’s results ofoperations, 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 bynatural 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 bedestructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areascan also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to otheroperating equipment. An example of such an event was the February 5, 2014 ice storm, which interrupted electric service delivery to customers inPECO’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. Naturaldisasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies may change the laws orregulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergencyplanning, security and environmental and radiological aspects. In addition, natural disasters could affect the availability of a secure andeconomical 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 distributionfacilities, the Registrants face a risk that their operations would be direct targets or indirect casualties of, an act of terror. Any retaliatory militarystrikes or sustained military campaign may affect their operations in unpredictable ways, such as changes in insurance markets and disruptions offuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cyber security of Exelon’sfacilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result ofterrorism, war, natural disasters, pandemic, credit crises, recession or other factors also may result in a decline in energy consumption, which mayadversely affect the Registrants’ results of operations and its ability to raise capital. In addition, the implementation of security guidelines andmeasures 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 itsgenerating 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 subjectto unforeseen occurrences or catastrophic events that may damage or destroy assets or interrupt operations. However, there can be no assurancethat the amount of insurance will be adequate to address such property and casualty losses. 60Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration’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 affectGeneration’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costsdue to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate itsnuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to produceadditional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’sobligations to committed third-party sales, including ComEd, PECO and BGE. These sources generally have higher costs than Generation incursto 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 refuelingoutages, 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 lowermargins 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 inincreased 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 downthe plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time andexpense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In eitherevent, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, Generationmay not achieve the anticipated results under its series of planned power uprates across its nuclear fleet. For plants operated but not whollyowned by Generation, Generation may also incur liability to the co-owners. For plants not operated and not wholly owned by Generation, fromwhich Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of theoperators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at nuclear plants notowned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affectGeneration’s results of operations or financial position. In addition, closure of generating plants owned by others, or extended interruptions ofgenerating plants or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricityin markets served by Generation. Nuclear major incident risk. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseenproblems have occurred both in the United States and abroad. The consequences of a major incident can be severe and include loss of life andproperty damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned byothers, may exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recovered frominsurers or the nuclear industry, could be borne by Generation and could have a material adverse effect on Generation’s results of operations orfinancial position. Additionally, an accident or other significant 61Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsevent at a nuclear plant within the United States or abroad, owned by others or Generation, may result in increased regulation and reduced publicsupport 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 throughmandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclearindustry 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 forGeneration’s nuclear operations. In previous years, NEIL has made distributions to its members but Generation cannot predict the level of futuredistributions or if they will occur at all. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated FinancialStatements for additional discussion of nuclear insurance. Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds willbe available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to theNRC 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 basedupon 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 actualresults 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 itscustomers 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 nuclearunits if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue tomake contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer hadrecourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trustfunds related to the former PECO units may be negatively affected and Exelon’s and Generation’s results of operations and financial positioncould be significantly affected. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additionalinformation. 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 makingadditional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRCminimum 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—AssetRetirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. 62Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration’s financial performance may be negatively affected by risks arising from its ownership and operation of hydroelectricfacilities. (Exelon and Generation) FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands orconnected to the interstate electric grid. The license for the Conowingo Hydroelectric Project expires August 31, 2015, and the license for theMuddy Run Pumped Storage Project expires on September 1, 2015. Generation cannot predict whether it will receive all the regulatory approvalsfor the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or astation cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increaseddepreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently includeassumptions that license renewal will be received. Generation may also lose revenue and incur increased fuel and purchased power expense tomeet 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 ofoperations or financial position. Similar effects may result from a change in the Federal Power Act or the applicable regulations due to events athydroelectric 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, areaffected by their ability to maintain the availability and reliability of their delivery and operational systems. (Exelon, ComEd, PECO andBGE) Failures of the equipment or facilities, including information systems, used in ComEd’s, PECO’s and BGE’s delivery systems can interruptthe electric transmission and electric and natural gas delivery, which could negatively impact related revenues, and increase maintenance andcapital 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 serviceterritory fail to perform as intended or are not successfully integrated with billing and other information systems, ComEd’s, PECO’s and BGE’sfinancial condition, results of operations, and cash flows could be adversely affected. Furthermore, if any of the financial, accounting, or other dataprocessing systems fail or have other significant shortcomings, ComEd’s, PECO’s or BGE’s financial results could be adversely affected. If anemployee causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating theoperational systems, ComEd’s, PECO’s or BGE’s financial results could also be adversely affected. In addition, dependence upon automatedsystems may further increase the risk that operational system flaws or employee tampering or manipulation of those systems will result in lossesthat are difficult to detect. The aforementioned failures or those of other utilities, including prolonged or repeated failures, can affect customer satisfaction and the levelof regulatory oversight and ComEd’s, PECO’s and BGE’s maintenance and capital expenditures. Regulated utilities, which are required to provideservice to all customers within their service territory, have generally been afforded liability protections against claims by customers relating tofailure of service. Under Illinois law, however, ComEd can be required to pay damages to its customers in some circumstances involving extendedoutages affecting large numbers of its customers, and those damages could be material to ComEd’s results of operations and cash flows. SeeNote 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regardingproceedings related to storm-related outages in ComEd’s service territory. 63Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsComEd’s, PECO’s and BGE’s respective ability to deliver electricity, their operating costs and their capital expenditures may benegatively 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 alternativerouting or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. Also, insufficientavailability of electric supply to meet customer demand could jeopardize ComEd’s, PECO’s and BGE’s ability to comply with reliability standardsand strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facilityretirements could result in PJM or FERC requiring ComEd, PECO and BGE to upgrade or expand their respective transmission systems throughadditional 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 appropriatereplacements, may lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss ofknowledge 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 technicaland support employees for their generation, transmission and distribution operations. If the Registrants are unable to successfully attract andretain 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. Asecurity breach of the physical assets or information systems of the Registrants, their competitors, RTOs and ISOs, or regulators could impactthe operation of the generation fleet and/or reliability of the transmission and distribution system or subject the Registrants to financial harmassociated 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 theindustry may be diminished, or Exelon and its subsidiaries may be subject to legal claims, any of which may contribute to the loss of customersand have a negative impact on the business and/or results of operations. ComEd’s, PECO’s and BGE’s deployment of smart meters throughouttheir service territories may increase the risk of damage from an intentional disruption of the system by third parties. As with most companies intoday’s environment, Exelon experiences attempts by hackers to infiltrate its corporate network. To date there have been no infiltrations that haveresulted in loss of data or any significant effects on business operations. Exelon utilizes a dedicated team of cyber security professionals toensure the protection of its information and ability to conduct business operations. Despite the measures taken by the Registrants to prevent asecurity breach, the Registrants cannot accurately assess the probability that a security breach may occur and are unable to quantify the potentialimpact of such an event. In addition, new or updated security regulations could require changes in current measures taken by the Registrants ortheir business operations and could adversely affect their results of operations, cash flows and financial position. 64Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe Registrants may make investments in new business initiatives, including initiatives mandated by regulators, and markets that maynot 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 valuechain. Generation is pursuing investment opportunities in renewables, development of natural gas generation, distributed generation, potentialexpansion of the existing natural gas and oil Upstream and wholesale gas businesses, and entry into liquefied natural gas. Such initiatives mayinvolve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, andunidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. As these markets mature, theremay be new market entrants or expansion by established competitors that increase competition for customers and resources. Additionally, it ispossible that FERC, state public utility commissions or others may impose certain other restrictions on such transactions. All of these factorscould 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 limitedto, cost recovery, regulatory concerns, cyber security and obsolescence of technology. Due to these risks, no assurance can be given that suchinitiatives 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 becompleted 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 Mergerby the holders of a majority of the outstanding shares of the PHI common stock, (2) the receipt of regulatory approvals required to consummatethe 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’scompliance with its obligations and covenants contained in the Merger Agreement. In addition, the obligation of Exelon to consummate the Mergeris subject to the required regulatory approvals not, individually or in the aggregate, imposing terms, conditions, obligations or commitments thatconstitute 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 theMerger 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 informationregarding 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 orimpose 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 theFERC, the FCC, the District of Columbia Public Service Commission, and the public utility commissions or similar entities in certain states inwhich the companies operate, including the Delaware Public Service Commission, MDPSC, the New Jersey Board of Public Utilities and theVirginia Department of Public Utilities. The Merger is also subject to 65Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsreview by the DOJ Antitrust Division, under the HSR Act, and the expiration or earlier termination of the waiting period (and any extension of thewaiting period) applicable to the Merger is a condition to closing the Merger. See Note 4—Mergers, Acquisitions, and Dispositions of the CombinedNotes 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 proposeor 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 willnot contain terms, conditions or restrictions that would be detrimental to the combined company after the completion of the Merger. The MergerAgreement generally permits Exelon to terminate the Merger Agreement if the final terms of any of the required regulatory consents or approvalsinclude burdensome conditions (as defined in the Merger Agreement). Any substantial delay in obtaining satisfactory approvals or the imposition ofany 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 obtainregulatory approvals without burdensome conditions, or the breach by Exelon of its obligations in respect of obtaining regulatory approvals, Exelonwill 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 theoutstanding nonvoting preferred securities purchased by Exelon in connection with the execution of the Merger Agreement for no considerationother 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 governmentalagencies will not be obtained or that certain other closing conditions will not be satisfied. If the Merger is not completed, the ongoing businesses ofExelon 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 certaincircumstances, 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 theMerger 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 twocompanies. Most of these costs will be transaction costs, including fees paid to financial and legal advisors related to the Merger and relatedfinancing 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 theMerger during the period of delay. 66Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon will also incur transaction fees and costs related to formulating integration plans. Additional unanticipated costs may be incurred in theintegration of the two companies’ businesses. Although Exelon expects that the elimination of costs, as well as the realization of other efficienciesrelated to the integration of the businesses, will exceed incremental transaction and Merger-related costs over time, this net benefit may not beachieved 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 integratingPHI’s business with Exelon’s existing businesses. The integration process may be complex, costly and time-consuming. The challengesassociated 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 ourstructure; • 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 andretain 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. Theseuncertainties may impair Exelon’s and/or PHI’s ability to attract, retain and motivate key personnel until the Merger is completed and for a periodof time thereafter, as employees and prospective employees may experience uncertainty about their future roles with the combined company. Inaddition, current and prospective Exelon and PHI employees may determine that they do not desire to work for the combined company for avariety 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 significantdiversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration processcould affect Exelon’s and/or PHI’s financial results. The process of integrating the operations of PHI may require a disproportionate amount ofresources and management attention. Exelon’s future operations and cash flows will depend to a significant degree upon Exelon’s ability tooperate PHI efficiently, achieve the strategic operating objectives for the business and realize cost savings and synergies. Exelon’s managementteam may encounter unforeseen difficulties in managing the integration. In order to successfully integrate PHI, Exelon’s management team willneed to focus on realizing anticipated synergies and cost savings on a timely basis while maintaining the efficiency of operations. Any substantialdiversion of management attention could affect Exelon’s ability to achieve operational, financial and strategic objectives. 67Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsWe 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 incash 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 foradditional 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 Exelonby reason of the merger could be adversely affected before or after the Merger closing as a result of previously unknown events or conditionsoccurring or existing before the Merger closing. Adverse changes in PHI’s business or operations could occur or arise as a result of actions byPHI, legal or regulatory developments including the emergence or unfavorable resolution of pre-acquisition loss contingencies, deteriorating generalbusiness, market, industry or economic conditions, and other factors both within and beyond the control of PHI. A significant decline in the valueof PHI assets to be acquired by Exelon or a significant increase in PHI liabilities to be assumed by Exelon could adversely affect the combinedcompany’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 acquisitionmethod of accounting for business combinations. The assets and liabilities of PHI will be consolidated with those of Exelon. The excess of thepurchase 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 isrequired to assess goodwill for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reportingunits. 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 valueof goodwill to the carrying amount would be required to determine if the goodwill is impaired. Such a potential impairment could result in a materialnon-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 theMerger. One of the conditions to the closing of the Merger is that no judgment (whether preliminary, temporary or permanent) or other order by anycourt 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 publicstockholders challenging the proposed Merger and seeking, among other things, to enjoin the defendants from consummating the Merger on theagreed-upon terms. Exelon has been named as a defendant in these lawsuits. Exelon has also been named in a federal court case with similarclaims. In September 2014, the parties reached a proposed settlement which is subject to court approval. Final court approval of the proposedsettlement is not expected to occur until the second quarter of 2015, at the earliest. 68Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIf a plaintiff in these or any other litigation claims that may be filed in the future is successful in obtaining an injunction prohibiting the partiesfrom completing the Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Merger in theexpected 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 andofficers. Private parties who may believe they are adversely affected by the Merger and individual states may bring legal actions under the antitrustlaws in certain circumstances or intervene in regulatory proceedings. Although Exelon and PHI believe the completion of the Merger will notconflict 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 ismade, what the result will be. Under the Merger Agreement, Exelon and PHI have agreed to use their reasonable best efforts to obtain allregulatory clearances necessary to complete the Merger as promptly as practicable. In addition, in order to complete the Merger, Exelon and PHImay 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 limitingExelon’s revenues after the completion of the Merger, or otherwise reducing the anticipated benefits from the Merger. In addition, any suchconditions, 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 withrespect to the parties’ respective operations pending completion of the Merger. In addition, Exelon may choose to waive requirements of theMerger Agreement, including some conditions to closing of the Merger. Any such amendments, alterations or waivers may have negativeconsequences 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 agreementsassociated 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 thatExelon may encounter delays, unexpected difficulties or costs in meeting these commitments in compliance with the terms of the relevantagreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties orfines that could adversely affect Exelon’s financial position and operating results. ITEM 1B.UNRESOLVED STAFF COMMENTS Exelon, Generation, ComEd, PECO and BGE None. 69Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 2.PROPERTIES Generation The following table describes Generation’s interests in net electric generating capacity by station at December 31, 2014: Station Region Location No. ofUnits PercentOwned PrimaryFuel Type PrimaryDispatchType NetGenerationCapacity (MW) Limerick Mid-Atlantic Sanatoga, PA 2 Uranium Base-load 2,317 Peach Bottom Mid-Atlantic Delta, PA 2 50 Uranium Base-load 1,165 Salem Mid-Atlantic Lower Alloways CreekTownship, NJ 2 42.59 Uranium Base-load 1,005 Calvert Cliffs Mid-Atlantic Lusby, MD 2 50.01 Uranium Base-load 878 Three Mile Island Mid-Atlantic Middletown, PA 1 Uranium Base-load 837 Oyster Creek Mid-Atlantic Forked River, NJ 1 Uranium Base-load 625 Conowingo Mid-Atlantic Darlington, MD 11 Hydroelectric Base-load 572 Criterion Mid-Atlantic Oakland, MD 28 Wind Base-load 70 Fourmile Mid-Atlantic Garrett County, MD 16 Wind Base-load 40 Solar Horizons Mid-Atlantic Emmitsburg, MD 1 Solar Base-load 14 Solar New Jersey 2 Mid-Atlantic Various, NJ 2 Solar Base-load 9 Solar New Jersey 1 Mid-Atlantic Various, NJ 4 Solar Base-load 8 Solar Maryland Mid-Atlantic Various, MD 9 Solar Base-load 7 Solar Federal Mid-Atlantic Trenton, NJ 1 Solar Base-load 4 Solar Maryland 2 Mid-Atlantic Pocomoke, MD 2 Solar Base-load 3 Solar New Jersey 3 Mid-Atlantic Middle Township, NJ 5 Solar Base-load 1 Muddy Run Mid-Atlantic Drumore, PA 8 Hydroelectric Intermediate 1,070 Eddystone 3, 4 Mid-Atlantic Eddystone, PA 2 Oil/Gas Intermediate 760 Croydon Mid-Atlantic West Bristol, PA 8 Oil Peaking 391 Perryman Mid-Atlantic Belcamp, MD 5 Oil/Gas Peaking 353 Handsome Lake Mid-Atlantic Kennerdell, PA 5 Gas Peaking 268 Riverside Mid-Atlantic Baltimore, MD 3 Oil/Gas Peaking 113 Westport Mid-Atlantic Baltimore, MD 1 Gas Peaking 115 Notch Cliff Mid-Atlantic Baltimore, MD 8 Gas Peaking 118 Richmond Mid-Atlantic Philadelphia, PA 2 Oil Peaking 98 Gould Street Mid-Atlantic Baltimore, MD 1 Gas Peaking 97 Philadelphia Road Mid-Atlantic Baltimore, MD 4 Oil Peaking 61 Eddystone Mid-Atlantic Eddystone, PA 4 Oil Peaking 60 Fairless Hills Mid-Atlantic Fairless Hills, PA 2 Landfill Gas Peaking 60 Delaware Mid-Atlantic Philadelphia, PA 4 Oil Peaking 56 Southwark Mid-Atlantic Philadelphia, PA 4 Oil Peaking 52 Falls Mid-Atlantic Morrisville, PA 3 Oil Peaking 51 Moser Mid-Atlantic Lower PottsgroveTwp., PA 3 Oil Peaking 51 Chester Mid-Atlantic Chester, PA 3 Oil Peaking 39 Schuylkill Mid-Atlantic Philadelphia, PA 2 Oil Peaking 30 Salem Mid-Atlantic Lower Alloways Creek Twp, NJ 1 42.59 Oil Peaking 16 Pennsbury Mid-Atlantic Morrisville, PA 2 Landfill Gas Peaking 6 Total Mid-Atlantic 11,420 Braidwood Midwest Braidwood, IL 2 Uranium Base-load 2,378 LaSalle Midwest Seneca, IL 2 Uranium Base-load 2,327 Byron Midwest Byron, IL 2 Uranium Base-load 2,344 Dresden Midwest Morris, IL 2 Uranium Base-load 1,845 Quad Cities Midwest Cordova, IL 2 75 Uranium Base-load 1,403 Clinton Midwest Clinton, IL 1 Uranium Base-load 1,069 Michigan Wind 2 Midwest Sanilac Co., MI 50 Wind Base-load 90 70(a)(b)(c)(d)(f)(f)(f)(g)(e)(h)(f)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsStation Region Location No. ofUnits PercentOwned PrimaryFuel Type PrimaryDispatchType NetGenerationCapacity (MW) Beebe Midwest Gratiot Co., MI 34 Wind Base-load 81 Michigan Wind 1 Midwest Huron Co., MI 46 Wind Base-load 69 Harvest 2 Midwest Huron Co., MI 33 Wind Base-load 59 Harvest Midwest Huron Co., MI 32 Wind Base-load 53 Beebe 1B Midwest Gratiot Co., MI 21 Wind Base-load 50 Ewington Midwest Jackson Co., MN 10 99 Wind Base-load 21 Marshall Midwest Lyon Co., MN 9 99 Wind Base-load 19 City Solar Midwest Chicago, IL 1 Solar Base-load 8 Norgaard Midwest Lincoln Co., MN 7 99 Wind Base-load 9 AgriWind Midwest Bureau Co., IL 4 99 Wind Base-load 8 Cisco Midwest Jackson Co., MN 4 99 Wind Base-load 8 Wolf Midwest Nobles Co., MN 5 99 Wind Base-load 6 CP Windfarm Midwest Faribault Co., MN 2 Wind Base-load 4 Blue Breezes Midwest Faribault Co., MN 2 Wind Base-load 3 Cowell Midwest Pipestone Co., MN 1 99 Wind Base-load 2 Solar Ohio Midwest Toledo, OH 2 Solar Base-load 1 Southeast Chicago Midwest Chicago, IL 8 Gas Peaking 296 Total Midwest 12,153 Whitetail ERCOT Laredo, TX 57 Wind Base-load 91 Wolf Hollow 1, 2, 3 ERCOT Granbury, TX 3 Gas Intermediate 704 Mountain Creek 8 ERCOT Dallas, TX 1 Gas Intermediate 565 Colorado Bend ERCOT Wharton, TX 6 Gas Intermediate 498 Quail Run ERCOT Odessa, TX 6 Gas Intermediate 488 Handley 3 ERCOT Fort Worth, TX 1 Gas Intermediate 395 Handley 4, 5 ERCOT Fort Worth, TX 2 Gas Peaking 870 Mountain Creek 6, 7 ERCOT Dallas, TX 2 Gas Peaking 240 LaPorte ERCOT Laporte, TX 4 Gas Peaking 152 Total ERCOT 4,003 Holyoke Solar New England Various, MA 2 Solar Base-load 4 Solar Massachusetts New England Various, MA 15 Solar Base-load 7 Solar Net Metering New England Uxbridge, MA 1 Solar Base-load 2 Solar Connecticut New England Various, CT 2 Solar Base-load 1 Mystic 8, 9 New England Charlestown, MA 6 Gas Intermediate 1,418 Mystic 7 New England Charlestown, MA 1 Oil/Gas Intermediate 575 Wyman New England Yarmouth, ME 1 5.9 Oil Intermediate 36 Medway New England West Medway, MA 3 Oil/Gas Peaking 117 Framingham New England Framingham, MA 3 Oil Peaking 33 New Boston New England South Boston, MA 1 Oil Peaking 16 Mystic Jet New England Charlestown, MA 1 Oil Peaking 9 Total New England 2,218 Solar New York New York Bethlehem, NY 1 Solar Base-load 2 Nine Mile Point New York Scriba, NY 2 50.01 Uranium Base-load 835 Ginna New York Ontario, NY 1 50.01 Uranium Base-load 288 Total New York 1,125 AVSR Other Lancaster, CA 1 Solar Base-load 242 Shooting Star Other Greensburg, KS 65 Wind Base-load 104 Exelon Wind 4 Other Gruver, TX 38 Wind Base-load 80 Bluegrass Ridge Other King City, MO 27 Wind Base-load 57 Conception Other Barnard, MO 24 Wind Base-load 50 Cow Branch Other Rock Port, MO 24 Wind Base-load 50 Mountain Home Other Glenns Ferry, ID 20 Wind Base-load 42 High Mesa Other Elmore Co., ID 19 Wind Base-load 40 Echo 1 Other Echo, OR 21 99 Wind Base-load 35 Sacramento PVEnergy Other Sacremento, CA 4 Solar Base-load 26 Cassia Other Buhl, ID 14 Wind Base-load 29 Wildcat Other Lovington, NM 13 Wind Base-load 27 Sunnyside Other Sunnyside, UT 1 50 Waste Coal Base-load 26 Echo 2 Other Echo, OR 10 Wind Base-load 20 71(a)(b)(c)(d)(f)(f)(f)(f)(f)(f)(f)(i)(f)(f)(g)(f)(g)(f)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsStation Region Location No. ofUnits PercentOwned PrimaryFuel Type PrimaryDispatchType NetGenerationCapacity (MW) Tuana Springs Other Hagerman, ID 8 Wind Base-load 17 Greensburg Other Greensburg, KS 10 Wind Base-load 13 Echo 3 Other Echo, OR 6 99 Wind Base-load 10 Exelon Wind 1 Other Gruver, TX 8 Wind Base-load 10 Exelon Wind 2 Other Gruver, TX 8 Wind Base-load 10 Exelon Wind 3 Other Gruver, TX 8 Wind Base-load 10 Exelon Wind 5 Other Texhoma, TX 8 Wind Base-load 10 Exelon Wind 6 Other Texhoma, TX 8 Wind Base-load 10 Exelon Wind 7 Other Sunray, TX 8 Wind Base-load 10 Exelon Wind 8 Other Sunray, TX 8 Wind Base-load 10 Exelon Wind 9 Other Sunray, TX 8 Wind Base-load 10 Exelon Wind 10 Other Dumas, TX 8 Wind Base-load 10 Exelon Wind 11 Other Dumas, TX 8 Wind Base-load 10 High Plains Other Panhandle, TX 8 99.5 Wind Base-load 10 Three Mile Canyon Other Boardman, OR 6 Wind Base-load 10 Solar Arizona Other Various, AZ 31 Solar Base-load 27 Outback Solar Other Christmas Valley, OR 1 Solar Base-load 5 Loess Hills Other Rock Port, MO 4 Wind Base-load 5 Denver Airport Solar Other Denver, CO 1 Solar Base-load 4 California PV Energy Other Various, CA 37 Solar Base-load 16 Solar California Other Various, CA 4 Solar Base-load 2 Solar Georgia Other Various, GA 10 Solar Base-load 9 Hillabee Other Alexander City, AL 3 Gas Intermediate 695 Grande Prairie Other Alberta, Canada 1 Gas Peaking 75 SEGS 4, 5, 6 Other Boron, CA 3 4.2-12.2 Solar Peaking 8 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 constantrate. 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 offdaily. 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% ofNine 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 thirdparties 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 ConsolidatedBalance 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, fuelrestrictions, 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, operationaloutages, reservoir performance, regulatory changes, asset sales, weather events, price effects and other factors. 72(a)(b)(c)(d)(f)(f)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certainexceptions. 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 ofinsurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition or results ofoperations. ComEd ComEd’s electric substations and a portion of its transmission rights of way are located on property that ComEd owns. A significant portionof its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that othersown. ComEd believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements, licenses andfranchise 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 Miles765,000 90345,000 2,656138,000 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, underwhich 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 itsinsured 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 portionof its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that othersown. 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. 73Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTransmission and Distribution PECO’s high voltage electric transmission lines owned and in service at December 31, 2014 were as follows: Voltage (Volts) Circuit Miles500,000 188230,000 548138,000 15669,000 200 (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 inDelaware 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 capacityof 157 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peakingcapability of 25 mmcf/day. In addition, PECO owns 31 natural gas city gate stations and direct pipeline customer delivery points at variouslocations 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, underwhich 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 itsinsured 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 ofits 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, ithas not necessarily undertaken to examine the underlying title to the land upon which the rights rest. 74(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTransmission and Distribution BGE’s high voltage electric transmission lines owned and in service at December 31, 2014 were as follows: Voltage (Volts) Circuit Miles500,000 218230,000 322138,000 54115,000 697 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 332mmcf/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 apropane-air plant located in Baltimore, Maryland, with a storage capacity of 546 mmcf and a send-out capacity of 85 mmcf/day. In addition, BGEowns 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 toits properties by fire or other perils, subject to certain exceptions. For its insured losses, BGE is self-insured to the extent that any losses arewithin the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on theconsolidated 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 securitymeasures 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 infrastructurevulnerabilities are addressed in order to maintain the reliability of the country’s energy systems. 75Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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. Forinformation regarding material lawsuits and proceedings, see Note 3—Regulatory Matters and Note 22—Commitments and Contingencies of theCombined 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. 76Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART 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 OFEQUITY 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 commonstock 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 sharebasis: 2014 2013 FourthQuarter ThirdQuarter SecondQuarter FirstQuarter FourthQuarter ThirdQuarter SecondQuarter FirstQuarter 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 77Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsStock Performance Graph The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exeloncommon 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. Value of Investment at December 31, 2009 2010 2011 2012 2013 2014Exelon Corporation $100 $74.88 $77.99 $53.48 $49.25 $66.68S&P 500 $100 $139.23 $139.23 $157.89 $204.63 $227.94S&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 127,002,904shares were indirectly held by Exelon. At January 31, 2015, in addition to Exelon, there were 297 record holders of ComEd common stock. Thereis no established market for shares of the common stock of ComEd. 78Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO As of January 31, 2015, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which wereindirectly 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 heldby 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 anydividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” isundefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to bepaid 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 ofcorporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does notbelieve these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meetExelon’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 sufficientto declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEdhas also agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of itscapital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued toComEd 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 anyshares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures whichwere 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 ofPEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinateddebentures 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 wasprohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on itscommon shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemakingprecedents 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 notifythe MDPSC that BGE’s equity ratio is at least 48% within five business days after dividend payment. There are no other limitations on BGEpaying common stock dividends unless: (1) BGE elects to defer 79Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsinterest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) anydividends (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) 4thQuarter 3rdQuarter 2ndQuarter 1stQuarter 4thQuarter 3rdQuarter 2ndQuarter 1stQuarter 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) 4thQuarter 3rdQuarter 2ndQuarter 1stQuarter 4thQuarter 3rdQuarter 2ndQuarter 1stQuarter 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 isqualified 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 2013 2012 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 80(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents (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 fullyconsolidated 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 isqualified 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 2013 2012 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 fullyconsolidated basis.(b)2012 financial results include the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012. 81(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents 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 isqualified 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 82Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data isqualified 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 isqualified 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 83Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents December 31, (In millions) 2014 2013 2012 2011 2010 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 interestentities 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. 84(a)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsItem 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 multiplegeographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale andretail customers. Generation also sells renewable energy and other energy-related products and services, and engages in natural gasand 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 theoperating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation fullyconsolidated 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 anddistribution 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 andtransmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale ofnatural 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 electricitydistribution 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, NewEngland, New York, ERCOT and other regions in Generation), ComEd, PECO and BGE. See Note 24—Segment Information of the CombinedNotes 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. Thecosts of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporateoperations 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 andAnalysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO and BGE. However, none ofthe Registrants makes any representation as to information related solely to any of the other Registrants. 85Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFinancial Results. The following consolidated financial results reflect the results of Exelon for the year ended December 31, 2014 comparedto the same period in 2013. The 2014 financial results only include the operations of CENG on a fully consolidated basis from the date Generationassumed 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 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 fuelexpense 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 operatingexpenses 6,998 2,409 1,261 1,309 59 12,036 10,518 (1,518) Equity in (losses) earnings of unconsolidatedaffiliates (20) — — — — (20) 10 (30) Gain (loss) on sales of assets 437 2 — — (2) 437 13 424 Gain on consolidation and acquisition ofbusinesses 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 stockdividends 184 — — 13 — 197 10 (187) Net income (loss) attributable to commonshareholders $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 fullyconsolidated 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 ofpurchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchasedpower 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 GAAPinformation 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 $1,719million for the year ended December 31, 2013, and diluted earnings per average common share were $1.88 for the year ended December 31, 2014as compared to $2.00 for the year ended December 31, 2013. 86 (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOperating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $262 million ascompared to 2013. The year-over-year increase reflects the inclusion of CENG’s results beginning April 1, 2014 and was primarily due to thefollowing 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 tothe Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, and favorable portfolio management activities in theNew England and South regions; partially offset by higher procurement costs for replacement power related to the extreme cold weatherin 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 atthe Constellation merger date and an increase related to the amortization of out-of-the money energy contracts recorded at fair valueupon 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 (bothoffset 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 andmaintenance 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 gasdistribution 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 June2014. The year-over-year increase in operating revenue net of purchased power and fuel expense was partially offset by the following unfavorablefactors: • Decrease of $1,095 million at Generation due to mark-to-market losses of $591 million in 2014 from economic hedging activitiescompared 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 fromApril 1, 2014 through December 31, 2014, an increase of $44 million resulting from expenses recorded for a Constellation mergercommitment, 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 futureasbestos-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 atBGE 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 throughDecember 31, 2014; 87Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents • 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 OPEBdiscount rates for 2014, partially offset by the inclusion of CENG’s pension and non-pension postretirement benefits expense fromApril 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, 2014through December 31, 2014, increased depreciation expense across the operating companies for ongoing capital expenditures, and higherregulatory 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 in2014. Exelon recorded a $261 million gain upon consolidation of CENG resulting from the difference in fair value of CENG’s net assets as ofApril 1, 2014, and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existingtransactions 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 onConstellation’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 effectiveincome tax rates. For further detail regarding the financial results for the years ended December 31, 2014 and 2013, including explanation of the non-GAAPmeasure 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 netincome, 88Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believes itrepresents 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-yearoperating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to benot directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as abasis 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’ presentationsor 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 withGAAP 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) EarningsperDilutedShare EarningsperDilutedShare Net Income Attributable to Common Shareholders $1,623 $1.88 $1,719 $2.00 Mark-to-Market Impact of Economic Hedging Activities 363 0.42 (310) (0.35) Unrealized Gains Related to NDT Fund Investments (86) (0.10) (78) (0.09) Plant Retirements and Divestitures (245) (0.28) (13) (0.02) Asset Retirement Obligation (13) (0.02) 7 0.01 Merger and Integration Costs 185 0.21 87 0.08 Amortization of Commodity Contract Intangibles 64 0.07 347 0.41 Reassessment of State Deferred Income Taxes (27) (0.03) 4 — Long-Lived Asset Impairments 435 0.50 110 0.14 Bargain-Purchase Gain on Integrys acquisition (28) (0.03) — — Gain on CENG Integration (159) (0.18) — — Tax Settlements (106) (0.12) — — CENG Non-Controlling Interest 62 0.07 — — Remeasurement of Like-Kind Exchange Tax Position — — 267 0.31 Midwest Generation Bankruptcy Charges — — 16 0.02 Amortization of the Fair Value of Certain Debt — — (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) onGeneration’s economic hedging activities. See Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail relatedto 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) onGeneration’s NDT fund investments for Non-Regulatory Agreement Units. See Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated FinancialStatements 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 oftaxes 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 anincrease 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). 89 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(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 professionalfees, employee-related expenses, integration activities, upfront credit facilities, merger commitments, and certain pre-acquisition contingencies, if and when applicable to theConstellation 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 ofintangibles assets, net, related to commodity contracts recorded at fair value at the 2012 Constellation merger date, the 2014 CENG integration date, and the 2014 Integrysacquisition 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 $250million). In 2013, reflects a charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects and the impairment of certain wind generatingassets (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 saleof 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 paymentsunder 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 quarterof 2013. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information. 90Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsMerger and Acquisition Costs As discussed above, Exelon has incurred and will continue to incur costs associated with the Integrys and PHI acquisitions includingemployee-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, CENGintegration, 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 $— $— $— $— $131 Regulatory Commitments 44 — — — 44 Transaction — — — — 26 Employee-Related 5 — — — 5 Other 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 $48 $4 $3 $1 $58 Other 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 oftransactions.(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 whichapproximately $100 million is expected to be capitalized to property, plant and equipment excluding the direct investment Exelon and PHI haveproposed 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 ofbenefits to BGE customers, and make certain investments in the City of Baltimore and the State of Maryland, resulting in an estimated directinvestment in the State of Maryland of approximately $1 billion. The direct investment estimate includes $95 million to $120 million for therequirement 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 91 (a) (b) (c) (d) (e) (d) (e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsfinancing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 whenthese outstanding contingencies were met by the developer. The building is expected to be ready for occupancy in approximately 2 years. SeeNote 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information related to thelease 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 strengthsof operational excellence and financial discipline. Exelon’s strategy is to leverage its integrated business model to create value and diversify itsbusiness. Exelon’s competitive and regulated businesses feature a mix of attributes that, when combined, offer shareholders and customers aunique value proposition: • Generation’s competitive businesses provide commodity exposure and a platform to diversify into adjacent markets, while providingresidual 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 theenergy 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 generationfleet by expanding Generation’s regional and technological footprint. Generation leverages its energy generation portfolio to ensure delivery ofenergy 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 inwell-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including itsnuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors helpGeneration 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 ratemakingmechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a net benefit to customers andthe community by increasing reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make theseinvestments prudently and at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilitiesplatform through enhanced standardization and sharing of best practices to achieve improved operational and financial results. Combined, theutilities plan to invest approximately $16 billion over the next five years in smart meter technology, transmission projects, gas infrastructure, andelectric 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 toreturn value to Exelon’s shareholders with a sustainable dividend throughout the energy commodity market cycle and through earnings growth fromattractive investment opportunities. 92Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsVarious market, financial, and other factors could affect the Registrants’ success in pursuing their strategies. Exelon continues to assessinfrastructure, operational, commercial, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS for additional informationregarding 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 restatedas of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelonname and be headquartered in Chicago. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each shareof PHI common stock. Exelon intends to fund the all-cash transaction using a combination of approximately $3.5 billion of debt, up to $1 billioncash from asset sales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). Inaddition, Exelon entered into a 364-day $7.2 billion senior unsecured bridge credit facility to support the contemplated transaction and provideflexibility for timing of permanent financing, which has subsequently been reduced to $3.2 billion as a result of execution of the debt and equitysecurity 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 ConsolidatedFinancial Statements for further information related to these transactions. In connection with the Merger Agreement, Exelon entered into asubscription agreement under which it has purchased $126 million of a new class of nonvoting, nonconvertible and nontransferable preferredsecurities in PHI as of December 31, 2014, with additional investments of $18 million to be made quarterly up to a maximum aggregate investmentof $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 paymentsdependent 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 FERChave approved the merger of PHI and Exelon. The Federal Communications Commission has also approved the transfer of certain PHIcommunications licenses. On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed byExelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits toACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with anaggregate 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 thefirst 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 ofextending the DOJ review period until 30 days after PHI and Exelon each has certified that it has substantially complied with the request. OnNovember 21, 2014, Exelon and PHI each certified that it had substantially complied with the request. Accordingly, the HSR Act waiting periodexpired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period underthe 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 itsinvestigation. Exelon and PHI will continue to work cooperatively with the DOJ regarding the proposed merger. 93Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 $48million related to acquisition and integration costs and $131 million of costs incurred to finance the transaction. The Merger Agreement alsoprovides for termination rights for both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to payExelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the transaction does not close due to a regulatoryfailure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities of PHI describedabove, as a result of PHI redeeming the outstanding nonvoting preferred securities for no consideration other than the nominal par value of thestock. Exelon has listed various potential risks relating to the pending merger with PHI (see Item 1A. Risk Factors), including difficulties that maybe encountered in satisfying the conditions to completion of the merger and the potential for developments that might have an adverse effect onExelon and the ability to realize the expected benefits of the merger. Exelon is taking steps to manage these risks and expects that the mergercan be completed on a basis favorable to the company’s shareholders and customers. Accordingly, Exelon anticipates closing the transaction inthe second or third quarter of 2015. Refer to Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated FinancialStatements 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, whichplaces downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’srevenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strongnatural 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 MidwesternUnited States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliabilityexpected by customers. To address this disconnect, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to itscurrent capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally seek to improve resource performanceand reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. To cover capital andother costs and risks that suppliers would incur to meet these higher reliability standards, suppliers would be allowed to include adders for suchcosts 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 ofmore efficient operations and to reduce the need for out of market energy payments to suppliers. Exelon participated actively in PJM’s stakeholderprocess through which PJM developed the proposal and is also actively participating in the FERC proceeding including filing comments. PJMasked 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 requirechanges. Subsidized Generation. The rate of expansion of subsidized generation, including low-carbon generation such as wind and solar energy, inthe markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations. 94Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsVarious states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation developmentwhich may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted in to law inJanuary 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale ofcapacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between theprice eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected threeproposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing theMaryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct anapproximately 700 MW combined cycle gas turbine in Waldorf, Maryland, that it projected will be in commercial operation by June 1, 2015. CPVhas subsequently sought to extend that date. The CfD mandated that utilities (including BGE) pay (or receive) the difference between CPV’scontract 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 theMDPCS in state and federal courts. Ultimately, the Exelon parties prevailed in obtaining orders from the U.S. Court of Appeals for the Third Circuitand the U.S. Court of Appeals for the Fourth Circuit effectively undoing the actions taken by the New Jersey legislature and the MDPSCrespectively. The matter has been appealed to the U.S. Supreme Court, and while the Court of Appeals decisions are helpful, there remains riskthe 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) offeredand cleared in PJM’s capacity market auctions held in May 2012, 2013, and 2014. In addition, CPV has announced its intention to move forwardwith 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 suppressedcapacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon’s market driven position. Whilethe court decisions in New Jersey and Maryland are positive developments, continuation of these state efforts, if successful and unabated by aneffective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/orenergy prices. Other states could seek to establish programs, which could substantially impact Exelon’s market driven position and could have asignificant effect on Exelon’s financial results of operations, financial position and cash flows. Exelon continues to monitor developments andparticipate in stakeholder and other processes to ensure that similar state subsidies are not developed. In addition, Exelon remains active inadvocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment tospecific 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 MarylandOrder. Energy Demand. Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity forComEd 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 thatGeneration can earn and the volumes that it is able to 95Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsserve. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within theindustry during the year. However, forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stayaggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedgegeneration output. Strategic Policy Alignment Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheetand credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity pricemovements, 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 quarterdividend was paid on June 10, 2014 to shareholders of record on May 16, 2014. All future quarterly dividends require approval by Exelon’s board ofdirectors. Exelon’s board of directors declared the third quarter 2014 dividend of $0.31 per share on Exelon’s common stock. The third quarter dividendwas 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 quarterdividend 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 dividendwill 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 futureof economically challenged generating assets will be based primarily on the economics of continued operation of the individual plants. If Exelonand Generation do not see a path to sustainable profitability in any of their plants, Exelon and Generation will take steps to retire those plants toavoid sustained losses. Retirement of plants could materially affect Exelon’s and Generation’s results of operations, financial position, and cashflows through, among other things, potential impairment charges, accelerated depreciation and decommissioning expenses over the plantsremaining 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 pricevolatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters intonon-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physicalforward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantlymitigate this risk for 2014 and 2015. This strategy has not changed as a result of recent and pending asset divestitures. However, Generation isexposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio iscurrently unhedged. As of December 31, 2014, the percentage of 96Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsexpected generation hedged for the major reportable segments was 93%-96%, 61%-64% and 31%-34% for 2015, 2016, and 2017 respectively. Thepercentage of expected generation hedged is the amount of equivalent sales divided by the expected generation (which reflects the divestitureimpact of Quail Run). Expected generation is the volume of energy that best represents our commodity position in energy markets from owned orcontracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibratedto market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale andretail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodityprice 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 obtainedpredominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services andcontracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas aresubject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to creditrisk 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 ofnon-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices thatmay be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have amaterial 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 fromretail customers. Growth Opportunities With an emphasis on innovation and entrepreneurship, Exelon is currently pursuing growth in both the utility and competitive energybusinesses. Identifying and capitalizing on emerging trends and technologies, Exelon plans to invest in new innovative technologies to competewith a new breed of energy players, leverage new technologies to create new or expand existing businesses, and improve productivity andefficiencies within our existing businesses. Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets andmarkets, 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 valuechain. • Leveraging its competencies, • Generation’s 2014 acquisition of Integrys allows Generation to expand its retail footprint further in an industry sector that continuesto 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 ofnatural gas generation plants that is supported by the trend of increasing natural gas supply. 97Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents • 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 decentralizedsystem. • Generation is also making investments across the natural gas value chain throughout North America, focusing initially onexpansion 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, earningsaccretion, and dividend stability. Additionally, ComEd, PECO and BGE anticipate making significant future investments in infrastructuremodernization, including smart meter and smart grid initiatives, storm hardening, and advanced reliability technologies. Upon obtaining variousapprovals, ComEd also plans to invest approximately $280 million to construct the Grand Prairie Gateway Transmission Line in Illinois alleviatingidentified congestion and enhancing reliability. ComEd, PECO and BGE invest in rate base where it provides a net benefit to customers and thecommunity by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made prudently andat 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 Meterand Smart Grid Initiatives. Liquidity Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining itsinvestment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligationsand invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet itsneeds 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 andcapital 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 aggregatemaximum 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 inthe European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As ofDecember 31, 2014, approximately 29%, or $2.5 billion, of the Registrants’ aggregate total commitments were with European banks, excluding theunsecured bridge facility to provide financing for the proposed PHI acquisition. The credit facilities include $8.5 billion in aggregate totalcommitments of which $7.3 billion was available as of December 31, 2014, due to outstanding letters of credit. There were no borrowings under theRegistrants’ credit facilities as of December 31, 2014. See Note 13—Debt and Credit Agreements of the Combined Notes to the ConsolidatedFinancial Statements for additional information on the credit facilities. 98Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTax 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 electricgenerating units. See discussion below for further details. The air and waste regulations will have a disproportionate adverse impact on fossil-fuelpower plants, requiring significant expenditures of capital and variable operating and maintenance expense, and will likely result in the retirement ofolder, marginal facilities. Due to their low emission generation portfolios, Generation and CENG will not be significantly directly affected by theseregulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have beenintroduced in the U.S. Congress that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the consideration of suchlegislation is unknown. Air Quality. In recent years, the U.S. EPA has been implementing a series of increasingly stringent regulations under the Clean Air Actrelating to NAAQS for conventional air pollutants (e.g., NOx, SO2 and particulate matter) as well as stricter technology requirements to controlHAPs (e.g., acid gases, mercury and other heavy metals) from electric generation units. The U.S. EPA continues to review and update its NAAQSwith a tightened particulate matter NAAQS issued in December 2012 and a tightened ozone NAAQS, to be finalized in late 2015, proposed forpublic 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 ofthese 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 inthe eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute toground-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 theU.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 forfurther 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. EPAhas exceeded its authority in certain material aspects of the CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemakingconsistent with its decision. On April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit Court decision and upheld CSAPR, andremanded the case to the D.C. Circuit Court to resolve the remaining implementation issues On November 21, 2014, the U.S. EPA issued anInterim Final Rule in which the Agency announced that it was tolling the effective dates for the CSAPR. The first phase of the CSAPR programstarted on January 1, 2015, with the second phase starting January 1, 2017. Also released on November 21, 2014, was a Notice of DataAvailability 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 revisionsto the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removalrates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolledcoal units) will have to make capital investments and incur higher operating expenses. It is expected that owners of smaller, older, uncontrolledcoal units will retire the units rather than make these investments. Coal units with existing controls that do not meet the MATS rule may 99Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsneed to upgrade existing controls or add new controls to comply. Owners of oil units not currently meeting the proposed emission standards maychoose to convert the units to light oils or natural gas, install control technologies, or retire the units. The MATS rule requires generating stationsto meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years inlimited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. On April 15, 2014, theD.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-firedelectric generators. The U.S. Supreme Court announced that it will review a single, yet critical, aspect of the MATS Rule—whether the U.S. EPAproperly considered compliance costs (e.g., pollution control capital expenditures and on-going operations and maintenance expense) indetermining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. If the Court finds that the U.S. EPA actedunreasonably, then implementation of the rule would be delayed until the U.S. EPA corrects any deficiencies. It is likely that the U.S. SupremeCourt 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 publiccomment, the establishment of a revised primary ozone standard in the range of 65-70 parts per billion (ppb) 8-hour average, a reduction from the2008 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-houraverage. 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 areproposed to be subjected to a March to October “ozone season.” In its proposed rule, the Agency also elected to set the secondary standard atthe same level and form as the primary standard. The Agency is expected to issue its final ozone NAAQS revision in October 2015. In December2012, 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 annualPM2.5 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 itexpects most areas of the country will be in attainment of the new PM2.5 NAAQS based on currently expected regulations, such as the MATSregulation. 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 willrequire states to submit state implementation plans (SIPs) for nonattainment areas by March 25, 2015. With regard to Texas and Maryland, nononattainment areas were identified in EPA’s final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions ofcounties, in each state were identified as nonattainment. Since the 2010 one-hour SO2 standard was finalized, EPA has issued a series ofguidance documents, and proposed a Data Requirement Rule that will be finalized in the summer of 2015 related to requirements for states relatedto the application of air quality monitoring and modeling in state implementation plans. Nonattainment county compliance with the one-hour SO2standard is required by March 25, 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable topredict 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 installpollution control technologies, including wet flue gas desulfurization technology for SO2 and acid gases, and selective catalytic reductiontechnology for NOx. 100Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsIn addition, as of December 31, 2014, Exelon had a $361 million net investment in coal-fired plants in Georgia subject to long-term leasesextending 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 therecorded residual lease values, after the impairments recorded in the second quarter of 2013 and 2014, final applications of the CSAPR and MATSregulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could bematerial. On January 15, 2013, EPA issued a final rule for NSPS and National Emissions Standards for Hazardous Air Pollutants (NESHAP) forreciprocating internal combustion engines (RICE NESHAP/NSPS). The final rule allows diesel backup generators to operate for up to 100 hoursannually under certain emergency circumstances without meeting emissions limitations, but requires units that operate over 15 hours to burn lowsulfur 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 demandresponse 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. OnJune 25, 2013, President Obama announced “The President’s Climate Action Plan,” a summary of executive branch actions intended to: reducecarbon emissions; prepare the United States for the impacts of climate change; and lead international efforts to combat global climate change andprepare for its impacts. Concurrent with the announcement of the Administration’s plan, the President also issued a Memorandum for theAdministrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 NewSource Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the U.S. EPA Administrator to issue twosets 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 CO2emissions for new fossil-fuel electric generating units, particularly coal-fired units. The Climate Action Plan also required the U.S. EPA to proposeby June 2014 GHG emission regulations for existing stationary sources under Section 111(d) of the Clean Air Act, and to issue final regulations byJune 2015. That proposed rule was published in the Federal Register on June 16, 2014. The proposed rule establishes emission reduction targetsfor 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 ofmarket-based instruments. While the nature and impact of the final regulations is not yet known, to the extent that the rule results in emissionreductions from fossil fuel fired plants, imposing some form of direct or indirect price of carbon in competitive electricity markets, Exelon’s overalllow-carbon generation portfolio results would benefit. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, whichbalances 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 besttechnology 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 eachfacility to determine the best technology available, followed by an implementation period. The timing of the various requirements for each facility isrelated to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to thediscretion of the state permitting director. 101Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsUntil the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, theimpact of compliance with the final rule is unknown. Should a state permitting director determine that a facility is required to install cooling towersto comply with the rule, that facility’s economic viability would be called into question. However, the likely impact of the rule has been significantlydecreased 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 combustionresiduals (CCR) from power plants, including the classification of CCR as non-hazardous waste under RCRA. The EPA ruling is effective 180 daysafter publication in the Federal Register, which is anticipated in early 2015. Under the regulation, CCR will continue to be regulated by most statessubject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coalash 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 anyremediation requirements that may be asserted for these former sites under the new federal regulations. For these reasons, Generation is unableto predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to formerly owned coal ashdisposal 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 toenvironmental 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 theMarch 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi NuclearPower Station, issued a report of its review of the accident, including tiered recommendations for future regulatory action by the NRC to be takenin the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not presentan imminent risk to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactorlicensees operating in the United States. The NRC and its staff are continuing to evaluate additional requirements. Generation has assessed theimpacts 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 aspreliminary engineering assumptions and analysis, indicate that the financial impact of compliance for Generation, net of expected co-ownerreimbursements, for the period from 2015 through 2019 is expected to be between approximately $325 million and $350 million of capital (includingapproximately $75 million for the CENG plants) and $75 million of operating expense (including approximately $25 million for the CENG plants). AsGeneration completes the design and installation planning for its actions, Generation will update these estimates. Further, Generation estimatesincremental 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, ifultimately required by the NRC. Generation’s current assessments are specific to the Tier 1 recommendations as the NRC has not taken specificaction with respect to the Tier 2 and Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent anyactions to comply with the requirements of Tier 2 102Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsand Tier 3 will impact their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industryassessments and actions and stakeholder input. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of FinancialCondition 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. Thepart 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 certaincategories of Swaps, incentives to shift Swap activity to exchange trading, margin and capital requirements, and other obligations designed topromote transparency. For non security-based Swaps including commodity Swaps, Dodd-Frank empowers the Commodity Futures TradingCommission (CFTC) to promulgate regulations implementing the law’s objectives. The primary aim of Dodd-Frank is to regulate the keyintermediaries in the Swaps market, which entities are either swap dealers (SDs), major swap participants (MSPs), and certain other financialentities, 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 thatexempts from margin requirements Swaps used by end-users to hedge or mitigate commercial risk. Moreover, the CFTC’s Dodd-Frank regulationspreserve the ability of end users in the energy industry to hedge their risks using Swaps without being subject to mandatory clearing, and exceptsor exempts end-users from many of the other substantive regulations. Accordingly, as an end-user, Generation is conducting its commercialbusiness in a manner that does not require registration with the CFTC as an SD or MSP. Generation does not anticipate transacting in the future ina 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 inaddition to certain international regulatory requirements still under development and that are similar to Dodd-Frank, Generation’s Swapcounterparties could be subject to additional and potentially significant capitalization requirements. These regulations could motivate the SDs andMSPs 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, ifany, 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, atthis time, management of ComEd, PECO and BGE continue to expect that their companies will not be materially affected by Dodd-Frank. Energy Infrastructure Modernization Act. Since 2011, ComEd’s distribution rates are established through a performance-based rateformula, pursuant to EIMA. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or beforeMay 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs andcurrent year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior yearand 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 basispoints (“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 regulatoryassets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenuerequirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. 103Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFormula Rate Tariff and Annual Reconciliation. On April 16, 2014, ComEd filed its annual distribution formula rate to request a totalincrease to the revenue requirement of $269 million. On December 11, 2014, the ICC issued its final order which increased the revenuerequirement by $232 million, reflecting an increase of $160 million for the initial revenue requirement for 2014 and an increase of $72 million relatedto the annual reconciliation for 2013. Approximately $23 million of the total $37 million revenue requirement disallowance is recoverable throughother rider-based mechanisms. The rate increase was set using an allowed return on capital of 7.06% (inclusive of an allowed return on commonequity 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 aseparate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work inprogress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’scontrol, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred priorto May 21, 2014 in ComEd’s transmission rate base. On October 22, 2014, the ICC issued an order approving ComEd’s Grand Prairie GatewayProject over the objection of numerous landowners and the City of Elgin. Four parties filed timely applications for rehearing before the ICC. OnNovember 25, 2014, the ICC denied the rehearing application filed by the Forest Preserve District of Kane County, but granted rehearing on theapplication of certain landowners who requested that the ICC consider an alternate route for a three-mile segment of the line in Kane County. Therehearing proceeding is currently pending and , the ICC must enter a final order on rehearing by April 24, 2015. On December 10, 2014, the ICCdenied the remaining two applications for rehearing. On January 15, 2015, those two parties, the City of Elgin and the SKP landowner group andUtility 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 onappeal until after the ICC issues its Order on rehearing. The ICC also filed a motion to consolidate those appeals. ComEd expects to beginconstruction 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 includedacquisition premiums/goodwill in its transmission formula rate, particularly in its capital structure and in the application of AFUDC. FERC alsodirected Ameren to make refunds for the implied increase in rates in prior years. Ameren filed for rehearing of the July 2012 order, which wasdenied in June 2014. FERC and Ameren are in the process of determining the amount of any potential refund. ComEd believes that the FERCorder 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 toComEd’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 theirtransmission planning procedures and their cost allocation methods applicable to certain new regional and interregional transmission projects. Aspart of the changes to the transmission planning procedures, the FERC required removal from all FERC-approved tariffs and agreements of a rightof 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, 104Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentscertain of the PJM transmission owners, including ComEd, PECO and BGE (collectively, the PJM Transmission Owners), submitted a filingasserting that their contractual rights embodied in the PJM governing documents continue to justify their right of first refusal to construct newreliability (and related) transmission projects and that the FERC should not be allowed to override such rights absent a showing that it is in thepublic interest to do so under the FERC’s “Mobile-Sierra” standard of review. This is a heightened standard of review which the PJM TransmissionOwners argued could not be satisfied based on the facts applicable to them. On March 22, 2013, FERC issued an order on the PJM ComplianceFiling and the filing of these PJM Transmission Owners (1) rejecting the arguments of those PJM Transmission Owners that changes to the PJMgoverning documents were entitled to review under the Mobile-Sierra standard, (2) accepting most of the PJM filing, removing the right-of-firstrefusal from the PJM tariffs, and (3) directing PJM to remove certain exceptions that it included in its compliance filing that FERC found did notcomply with Order No. 1000. FERC’s order could enable third parties to seek to build certain regional transmission projects that had previouslybeen reserved for the PJM Transmission Owners, potentially reducing ComEd’s, PECO’s and BGE’s financial return on new investments in energytransmission facilities. Numerous parties sought rehearing of the FERC’s March 22, 2013 order, including the PJM Transmission Owners whosought rehearing of the FERC’s rejection of their Mobile-Sierra and related arguments. PJM’s compliance filing was made on July 22, 2013. OnMay 15, 2014, FERC denied the rehearing requests except with respect to one issue on when PJM could consider state and local laws inevaluating projects. FERC generally accepted the July 22, 2013, Compliance Filing but required several minor additional changes. FirstEnergy andat 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 hasintervened in the FirstEnergy appeal. Several parties have filed requests for rehearing or clarification concerning the changes set forth in theMay 15, 2014, Order. On December 18, 2014, FERC issued an order conditionally accepting part of the PJM-MISO interregional Order No. 1000compliance filing, rejecting a MISO proposal concerning cost allocation for cross-border reliability projects and directing a further compliance filingby 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 PepcoHoldings, Inc. companies relating to their respective transmission formula rates. BGE’s formula rate includes a 10.8% base rate of return oncommon equity (ROE) and a 50 basis point incentive for participating in PJM (the latter of which is conditioned upon crediting the first 50 basispoints of any incentive ROE adders). The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rateprocess. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the revenuessubject to refund are limited to a fifteen month period, the earliest date from which the base ROE could be adjusted and refunds required is thedate 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 judgeprocedures for the complaint, and set a refund effective date of February 27, 2013. BGE, the PHI companies and the parties began settlementdiscussions under the guidance of a FERC administrative law judge on September 23, 2014. On November 24, 2014, the Settlement Judgeinformed FERC and the Chief Judge that the parties had reached an impasse and determined that a settlement was not possible. The SettlementJudge recommended termination of settlement proceedings. On November 26, 2014, the Chief Judge issued an order terminating the settlementproceeding, 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 regardingthe base ROE of the transmission business seeking a 105Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsreduction from 10.8% to 8.8%. The filing of the second complaint creates a second refund window. By order issued on February 9, 2015, FERCestablished 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 arefund to customers of transmission revenue for the two maximum fifteen month periods will be required. However, BGE is unable to estimate themost likely refund amount for either complaint at this time, and has therefore established a reserve, which is not material, representing the low endof a reasonably possible estimated range of loss. Additionally, management is unable to estimate the maximum exposure of a potential refund atthis time, which may have a material impact on BGE’s results of operations and cash flows. The estimated annual ongoing reduction in revenues ifFERC approved the ROEs requested by the parties in their filings is approximately $11 million. If FERC were to order a reduction of BGE’s baseROE 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 equityfor certain new transmission investment), the result of the first fifteen month refund window would be a refund to customers of approximately $13million. 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 anyincentives that were credited to the base return on equity for certain new transmission investment) and the refund period extended for a full fifteenmonths, the result would be a refund to customers of approximately $14 million. See Note 3—Regulatory Matters of the Combined Notes toConsolidated Financial Statements for additional information. The Maryland Strategic Infrastructure Development and Enhancement Program. In February 2013, the Maryland General Assemblypassed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptlyrecover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, theGovernor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSCand with the MDPSC’s approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charginggas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surchargesto residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actualexpenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs forthe infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate caseevery 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 MDPSCapproved 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 2015project 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 Exelonand 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 issuedby the MDPSC on BGE’s infrastructure replacement plan. On September 5, 2014, the Baltimore City Circuit Court affirmed the MDPSC decisionon BGE’s infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential 106Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsconsumer 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 estimatesand assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Managementdiscusses these policies, estimates and assumptions with its accounting and disclosure governance committee on a regular basis and providesperiodic updates on management decisions to the audit committee of the Exelon board of directors. Management believes that the accountingpolicies described below require significant judgment in their application, or estimates and assumptions that are inherently uncertain and that maychange in subsequent periods. Additional discussion of the application of these accounting policies can be found in the Combined Notes toConsolidated 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 guidancerequires 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 multipleoutcome scenarios. The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the keyassumptions 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 thecosts and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within its industry andother 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 coststudies 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 othercosts. Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenariosfor decommissioning costs, approaches and timing on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of thelikelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. Probabilities are assigned toalternative decommissioning approaches which assess the likelihood of performing DECON (a method of decommissioning shortly after thecessation of operation in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed andsafely buried in a LLRW landfill or decontaminated to a level that permits property to be released for unrestricted use), Delayed DECON (similar tothe 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 storedand 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 107Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsthe likelihood of continued operation through current license lives or through anticipated license renewals. Generation’s probabilistic cash flowmodels also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation assumes DOE will begin accepting SNF in2025. The SNF acceptance date was based on management’s estimates of the amount of time required for DOE to select a site location anddevelop 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 OysterCreek, in determining its nuclear decommissioning ARO. The current NRC license for Oyster Creek expires in 2029. On December 8, 2010, Exelonannounced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. As a result of this decision theexpected economic life of Oyster Creek was reduced by 10 years to correspond to Exelon’s current best estimate as to the timing of ceasinggeneration operations at the Oyster Creek unit in 2019. Generation has successfully secured 20-year operating license renewal extensions forseventeen of its nuclear units (including the two Salem units co-owned by Generation, but operated by PSEG), and none of Generation’sapplications for an operating license extension has been denied. For its remaining seven operating units, Generation is in various stages of theprocess of pursuing similar extensions and has filed license renewal applications for six operating nuclear units and has until 2021 to seek licenserenewal for one operating nuclear unit. Generation’s assumption regarding license extension for ARO determination purposes is based in part onthe good current physical condition and high performance of these nuclear units, the favorable status of the ongoing license renewal proceedingswith the NRC, and the successful renewals for seventeen units to date. Generation estimates that the failure to obtain license renewals at any ofthese nuclear units (assuming all other assumptions remain constant) would increase its ARO on average approximately $300 million per unit as ofDecember 31, 2014. The size of the increase to the ARO for a particular nuclear unit is dependent upon the current stage in its original licenseterm and its specific decommissioning cost estimates. If Generation does not receive license renewal on a particular unit, the increase to the AROmay 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 guidancerequired Generation to establish an ARO at fair value at the time of the initial adoption of the current accounting standard. Subsequent to the initialadoption, the ARO is adjusted for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions, asdescribed above. Under the current accounting framework, the ARO is not required or permitted to be re-measured for changes in the CARFR that occur inisolation. This differs from the accounting requirements for other long-dated obligations, such as pension and other post-employment benefits thatare required to be re-measured as and when corresponding discount rates change. If Generation’s future nominal cash flows associated with theARO were to be discounted at current prevailing CARFRs, the obligation would increase from approximately $7.0 billion to approximately $8.6billion. The ultimate decommissioning obligation will be funded by the NDTs. The NDTs are recorded on Exelon’s and Generation’s ConsolidatedBalance 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% to6.3%. To illustrate the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing ofcash flows, can have on the valuation of the ARO: i) had Generation used the 2013 CARFRs rather than the 2014 CARFRs in performing its thirdquarter 2014 ARO update, Generation would have reduced the ARO by approximately $190 million as compared to 108Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsthe actual decrease to the ARO of $125 million; and ii) if the CARFR used in performing the third quarter 2014 ARO update (which also reflectedincreases in the amounts and changes to the timing of projected cash flows) was increased or decreased by 100 basis points, the ARO wouldhave 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. Theimpact 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 assumptionsconstant (dollars in millions): Change in ARO Assumption Increase (Decrease) toARO atDecember 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 ofthe low-cost scenario by 10 percentage points $290 Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of theSAFSTOR scenario by 10 percentage points $420 Increase the likelihood of operating through current license lives by 10 percentage points and decrease thelikelihood 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 ratesof 100 basis points $(270) Extend the estimated date for DOE acceptance of SNF to 2030 coupled with a decrease in discount ratesof 100 basis points $1,100 For more information regarding accounting for nuclear decommissioning obligations, see Note 1—Significant Accounting Policies and Note15—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 ofComEd in 2000 as part of the PECO/Unicom Merger. Under the provisions of the authoritative guidance for goodwill, ComEd is required to performan assessment for possible impairment of its goodwill at least annually or more frequently if an event occurs or circumstances change that wouldmore likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. Under the authoritative guidance, a reporting unitis an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested forimpairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financialinformation is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment for itscombined 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. 109Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsEntities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitativeassessment 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 ofqualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. Ifan entity bypasses the qualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fairvalue is less than its carrying amount, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of thereporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step isperformed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accountingguidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairmentloss is recorded as a reduction to goodwill and a charge to operating expense. Application of the goodwill impairment test requires managementjudgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using aweighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair valueanalyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows forComEd’s business and the fair value of debt. In applying the second step (if needed), management must estimate the fair value of specific assetsand liabilities of the reporting unit. See Note 1—Significant Accounting Policies, Note 10—Intangible Assets and Note 14—Income Taxes of theCombined 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 recordedat their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assetsacquired and liabilities assumed is recognized as goodwill on the balance sheet if it exceeds the estimated fair value and as a bargain purchasegain on the income statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requiresmanagement’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions withrespect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. Thejudgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimateduseful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such asthrough depreciation and amortization expense. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to ConsolidatedFinancial 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 thatGeneration has acquired. The initial amount recorded represents the fair value of the contract at the time of acquisition, and the balance isamortized over the life of the contract in relation to the present value of the underlying cash flows. Amortization expense and income are recordedthrough 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. 110Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsImpairment 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, forimpairment when circumstances indicate the carrying value of those assets may not be recoverable. Indicators for impairment may include adeteriorating business climate, including current energy prices and market conditions, condition of the asset, specific regulatory disallowance, orplans 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 estimatesof future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cashflows requires assumptions regarding forecasted commodity prices for the sale of power, costs of fuel and the expected operations of assets. Avariation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could havea significant effect on the consolidated financial statements. An impairment evaluation is based on an undiscounted cash flow analysis at thelowest level at which cash flows of the long-lived assets or asset groups are largely independent of other groups of assets and liabilities. For thegeneration business, the lowest level of independent cash flows is determined by evaluation of several factors, including the geographic dispatchof the generation units and the hedging strategies related to those units as well as the associated intangible contract assets recorded on thebalance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from thecustomer supply and risk management activities, including cash flows from contracts that are accounted for as intangible contract assets andliabilities recorded on the balance sheet. In certain cases generating assets may be evaluated on an individual basis where those assets arecontracted 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 isperformed. Impairment may occur if the carrying value of the asset or asset group exceeds the future undiscounted cash flows. When theundiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined bymeasuring 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 orasset group is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimatedfuture cash flows generated by the assets and market discount rates. Events and circumstances often do not occur as expected and there willusually be differences between prospective financial information and actual results, and those differences may be material. Accordingly, to theextent that any of the information used in the fair value analysis requires judgment, the resulting fair market value would be different. As such, thedetermination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue andgeneration forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial andindustry sources. An impairment determination would require the affected Registrant to reduce the value of either the long-lived asset or assetgroup, 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 gasand oil Upstream properties occurs if there are no firm plans to continue drilling, lease expiration is at risk, historical experience indicates a declinein carrying value below fair value or the price of the underlying commodity significantly declines. 111Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon holds investments in coal-fired plants in Georgia subject to long-term leases. The investments are accounted for as direct financinglease investments. The investments represent the estimated residual values of the leased assets at the end of the respective lease terms. On anannual basis, Exelon reviews the estimated residual values of its direct financing lease investments and records an impairment charge if thereview indicates an other than temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair valueof the residual values of its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, that takesinto consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operatethe plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value includefundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimatedremaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contracts associated with theplants 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 investmenthas experienced a decline in value that is not temporary in nature. Additionally, if one of Generation’s equity method investments recognizes animpairment, Generation would record its proportionate share of that impairment loss through its equity earnings (losses) of unconsolidatedaffiliates. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for a discussion of assetimpairment 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. TheRegistrants complete depreciation studies every five years, or more frequently in an event, regulation action, or change in retirement patternsindicate an update is necessary. The estimation of service lives requires management judgment regarding the period of time that the assets will bein use. As circumstances warrant, the estimated service lives are reviewed to determine if any changes are needed. Depreciation rates incorporateassumptions on interim retirements based on actual historical retirement experience. To the extent interim retirement patterns change, this couldhave a significant impact on the amount of depreciation expense recorded in the income statement. Changes to depreciation estimates resultingfrom a change in the estimated end of service lives could have a significant impact on the amount of depreciation expense recorded in the incomestatement. See Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regardingdepreciation 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 licenserenewals 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 economicand capital requirements. The estimated service lives of hydroelectric facilities are based on the 112Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsremaining useful lives of the stations, which assume a license renewal extension of the Conowingo and Muddy Run operating licenses. A changein depreciation estimates resulting from Generation’s extension or reduction of the estimated service lives could have a significant effect onGeneration’s results of operations. Generation completed a depreciation rate study during the first quarter of 2010, which resulted in the implementation of new depreciationrates effective January 1, 2010. Constellation completed a depreciation rate study during the fourth quarter of 2010, which resulted in theimplementation 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 filedthe updated depreciation rates with both FERC and the ICC in January 2014. This resulted in the implementation of new depreciation rateseffective 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 ratestudy 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 updateddepreciation study in 2015 and expects this to result in new depreciation rates effective in the first quarter of 2015 for electric transmission assetsand 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 rateswith the MDPSC for both its electric distribution and gas assets. Revisions to depreciation rates from this filing were finalized and effectiveDecember 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, BGEand BSC employees. See Note 16—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional informationregarding 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 postretirementbenefit plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing therequired assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs isaffected by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, theanticipated rate of increase of health care costs, Exelon’s expected level of contributions to the plans, the incidence of participant mortality, theexpected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length ofservice, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annuallyand upon any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed onpension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains orlosses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expectedaverage remaining service period of plan participants. Pension and other postretirement benefit costs attributed to the operating companies arelabor costs and are ultimately allocated to projects within the operating companies, some of which are capitalized. 113Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPension and other postretirement benefit plan assets include equity securities, including U.S. and international securities, and fixed incomesecurities, as well as certain alternative investment classes such as real estate, private equity and hedge funds. See Note 16—RetirementBenefits of the Combined Notes to Consolidated Financial Statements for information on fair value measurements of pension and otherpostretirement plan assets, including valuation techniques and classification under the fair value hierarchy in accordance with authoritativeguidance. Expected Rate of Return on Plan Assets. The long-term EROA assumption used in calculating pension costs was 7.00%, 7.50% and7.50% for 2014, 2013 and 2012, respectively. The weighted average EROA assumption used in calculating other postretirement benefit costs was6.59%, 6.45% and 6.68% in 2014, 2013 and 2012, respectively. The pension trust activity is non-taxable, while other postretirement benefit trustactivity is partially taxable. The current year EROA is based on asset allocations from the prior year end. In 2010, Exelon began implementation ofa liability-driven investment strategy in order to reduce the volatility of its pension assets relative to its pension liabilities. Over time, Exelon hasdecreased its equity investments and increased its investments in fixed income securities and alternative investments within the pension assetportfolio in order to achieve a balanced portfolio of liability hedging and return-generating assets. See Note 16—Retirement Benefits of theCombined Notes to Consolidated Financial Statements for additional information regarding Exelon’s asset allocations. Exelon used an EROA of7.00% 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 planassets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. Indetermining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value thatrecognizes 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 calculatedvalue approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For otherpostretirement 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. Theactual 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% and3.92%, respectively, at December 31, 2014. The discount rates at December 31, 2014 represent weighted-average rates for the majority of pensionand other postretirement benefit plans. At December 31, 2014 and 2013, the discount rates were determined by developing a spot rate curve basedon the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to therelated pension and other postretirement benefit obligations. The spot rates are used to discount the estimated distributions under the pension andother postretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizesan 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. Exelonused discount rates ranging from 3.94% and 3.92% to estimate the majority its 2015 pension and other postretirement benefit costs, respectively. 114Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsHealth Care Reform Legislation. In March 2010, the Health Care Reform Acts (the Acts) were signed into law. The Acts include a provisionthat imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a40% rate. Although the excise tax does not go into effect until 2018, accounting guidance requires Exelon to incorporate the estimated impact ofthe excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exelon continues to monitor the Department ofLabor and IRS for additional guidance. Effective in 2002, Constellation amended its other postretirement benefit plans for all subsidiaries other thanNine 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 hascapped the rate of claims growth for certain legacy Exelon plan participants over age 65, exposure to the excise tax remains. Certain keyassumptions are required to estimate the impact of the excise tax on the other postretirement obligation for legacy Exelon plans, includingprojected inflation rates (based on the CPI), and under what circumstances pre- and post-65 retiree benefits can be aggregated in determining thepremium 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 benefitplans for participant populations with plan designs that do not have a cap on cost growth. Accounting guidance requires that annual health carecost estimates be developed using past and present health care cost trends (both for Exelon and across the broader economy), as well asexpectations of health care cost escalation, changes in health care utilization and delivery patterns, technological advances and changes in thehealth status of plan participants. Therefore, the trend rate assumption is subject to significant uncertainty. Exelon assumed an initial health carecost 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 populationadjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon historically used a mortality basetable for its accounting valuation that is consistent with the IRS required table for funding (referred to as RP-2000) and its correspondingimprovement scale. During 2014, the Society of Actuaries (SOA) issued an updated mortality table (referred to as RP-2014) and improvementscale that suggests significant mortality improvement over the prior table. Exelon has a substantial employee population that provides a crediblebasis for mortality evaluation. Exelon engaged its actuaries to conduct a mortality study of Exelon’s actual experience over a five year period ascompared to the RP-2000 and RP-2014 tables, which resulted in a determination that the RP-2000 more closely aligns with Exelon’s actualmortality experience. The study also considered available improvement scales. Management concluded that the RP-2000 and a more recentimprovement scale issued by the SOA with certain adjustments to long-term improvement rates represent its best estimate of mortality. Exelon isutilizing the Scale BB 2-Dimensional improvement scale with long-term improvements of 0.75% (as compared to the 1% incorporated in the issuedtable) for its mortality improvement assumption. The change in assumption resulted in increases of $361 million and $117 million in the pensionand other postretirement benefits obligations, respectively and an increase in 2015 cost of $45 million and $20 million for pension and otherpostretirement benefits, respectively. 115Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptionsdiscussed above, while holding all other assumptions constant (dollars in millions): Actuarial Assumption Change inAssumption Pension Other PostretirementBenefits Total Change in 2014 cost: Discount rate 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 1.00% N/A 35 35 (1.00)% N/A (24) (24) Change in benefit obligation at December 31, 2014: Discount rate 0.5% (1,053) (245) (1,298) (0.5)% 1,156 271 1,427 Health care cost trend rate 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 discountrate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon implemented a liability-driven investmentstrategy 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 pensionasset 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 actuarialgains and losses, as applicable, based on participants’ average remaining service periods. The average remaining service period of defined benefitpension 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 periodto benefit eligibility age and amortizes its transition obligations and certain actuarial gains and losses over participants’ average remaining serviceperiod to expected retirement. The average remaining service period of postretirement benefit plan participants related to benefit eligibility age was9.1 years, 8.7 years and 8.9 years for the years ended December 31, 2014, 2013 and 2012, respectively. The average remaining service period ofpostretirement 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 foraccounting for certain types of regulations, which requires Exelon, ComEd, PECO and BGE to reflect the effects of cost-based rate regulation intheir financial statements. This guidance is applicable to entities with regulated operations that meet the following criteria: (1) rates are establishedor approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonableexpectation that rates are set at levels that will recover the entities costs from customers. Regulatory assets represent incurred costs that havebeen deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) the excessrecovery of costs or 116 (a)(b) (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsaccrued 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 haveconcluded that the operations of ComEd, PECO and BGE meet the criteria to apply the authoritative guidance. If it is concluded in a future periodthat a separable portion of those operations no longer meets the criteria of this guidance, Exelon, ComEd, PECO and BGE would be required toeliminate any associated regulatory assets and liabilities and the impact would be recognized in the Consolidated Statements of Operations andcould be material. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional informationregarding 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 andliabilities 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’sjurisdictions, and factors such as changes in applicable regulatory and political environments. Furthermore, Exelon, ComEd, PECO and BGEmake other judgments related to the financial statement impact of their regulatory environments, such as the types of adjustments to rate basethat will be acceptable to regulatory bodies, if any, to which costs will be recoverable through rates. Refer to the revenue recognition discussionbelow 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 authoritativeguidance for contingencies as to the amount of revenues billed under certain regulatory orders that may ultimately be refunded to customers uponfinalization of applicable regulatory or judicial processes. These assessments are based, to the extent possible, on past relevant experience withregulatory bodies in ComEd’s, PECO’s and BGE’s jurisdictions, known circumstances specific to a particular matter and hearings held with theapplicable regulatory body. If the assessments and estimates made by Exelon, ComEd, PECO and BGE are ultimately different than actualregulatory 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 financialstatements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts onthe 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 toplanned future debt issuances and changes in the fair value of outstanding debt. Generation uses a variety of derivative and non-derivativeinstruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases and otherenergy-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 withGeneration 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 alsoentered 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 117Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsRegistrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 12—Derivative Financial Instrumentsof 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 acontract qualifies as a derivative under this guidance requires that management exercise significant judgment, including assessing the marketliquidity as well as determining whether a contract has one or more underlyings and one or more notional amounts. Further, interpretive guidancerelated to the authoritative literature continues to evolve, including how it applies to energy and energy-related products. Changes in management’sassessment of contracts and the liquidity of their markets, and changes in authoritative guidance related to derivatives, could result in previouslyexcluded contracts being subject to the provisions of the authoritative derivative guidance. Generation has determined that contracts to purchaseuranium, contracts to purchase and sell capacity in certain ISO’s, certain emission products and RECs do not meet the definition of a derivativeunder the current authoritative guidance since they do not provide for net settlement and neither the uranium, certain capacity, emission nor theREC markets are sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. If these markets do becomesufficiently liquid in the future and Generation would be required to account for these contracts as derivative instruments, the fair value of thesecontracts would be accounted for consistent with Generation’s other derivative instruments. In this case, if market prices differ from the underlyingprices of the contracts, Generation would be required to record mark-to-market gains or losses, which may have a significant impact to Exelon’sand 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 thatqualify for, and are elected under, the normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedgeaccounting are classified as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlyinghedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective inoffsetting the change in the hedged cash flows of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings whenthe underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. Forcommodity transactions, effective with the date of the Constellation merger, Generation no longer utilizes the election provided for by the cash flowhedge designation and de-designated all of its existing cash flow hedges prior to the Constellation merger. Because the underlying forecastedtransactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will bereclassified 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 flowhedges. The effect of this decision is that all economic hedges for commodities are recorded at fair value through earnings for the combinedcompany. In addition, for energy-related derivatives entered into for proprietary trading purposes, changes in the fair value of the derivatives arerecognized in earnings each period. For economic hedges that are not designated for hedge accounting for ComEd, PECO and BGE, changes inthe 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 tobuy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase andsell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some ofthese contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have beendesignated as normal purchases and normal sales and are thus not required to be recorded at fair value, but rather 118Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentson an accrual basis of accounting. Determining whether a contract qualifies for the normal purchases and normal sales exception requires thatmanagement exercise judgment on whether the contract will physically deliver and requires that management ensure compliance with all of theassociated qualification and documentation requirements. Revenues and expenses on contracts that qualify as normal purchases and normalsales are recognized when the underlying physical transaction is completed. Contracts which qualify for the normal purchases and normal salesexception are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over areasonable period of time and is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part ofComEd’s energy procurement process, PECO’s full requirement contracts and block contracts under the PAPUC-approved DSP program, most ofPECO’s natural gas supply agreements and all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives qualifyfor 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 isin accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within theguidelines of the RMP. As a part of accounting for derivatives, the Registrants make estimates and assumptions concerning future commodity prices, loadrequirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changesin the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivativetransactions. In accordance with the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fairvalue 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 arecategorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokersor over-the-counter, on-line exchanges are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices andare obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed andcorroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includesconsideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The Registrant’s derivatives are tradedpredominately at liquid trading points. The remaining derivative contracts are valued using the Black model, an industry standard option valuationmodel. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, and assumptions of thefuture prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as genericforwards, swaps and options, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade inless liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs. In instanceswhere 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 themodel inputs generally are not observable. The Registrants consider nonperformance risk, including credit risk in the valuation of derivativecontracts categorized in Level 1, 2 and 3, including both historical and current market data in its assessment of nonperformance risk, includingcredit 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 aretypically designated as fair value hedges, as a means to achieve the targeted level of variable-rate debt as a percent of total debt. Additionally, theRegistrants 119Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsmay use forward-starting interest rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings and floating tofixed swaps for project financing. In addition, Generation enters into interest rate derivative contracts to economically hedge risk associated withthe interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the economic hedge andproprietary trading activity is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rateexposure. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or change in market interest rates. Tomanage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizesforeign currency derivatives, which are typically designated as economic hedges. The fair value of the agreements is calculated by discounting thefuture net cash flows to the present value based on the terms and conditions of the agreements and the forward interest rate and foreign exchangecurves. As these inputs are based on observable data and valuations of similar instruments, the interest rate and foreign exchange derivatives areprimarily categorized in Level 2 in the fair value hierarchy. Certain exchange based interest rate derivatives that are valued using unadjustedquoted 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 Assetsand Liabilities and Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additionalinformation 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 uncertaintyrelated to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. In accordance with applicable authoritativeguidance, 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 ofbeing 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 therecognition 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 todetermine whether the recognition threshold has been met and, if so, the appropriate amount of unrecognized tax benefits to be recorded in theRegistrants’ consolidated financial statements. The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and theirintent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess their ability toutilize 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 notbe 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 asresults of audits and examinations of filed tax returns by taxing authorities. While the Registrants believe the resulting tax balances as ofDecember 31, 2014 and 2013 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of taxmatters could result in favorable or 120Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsunfavorable adjustments to their consolidated financial statements and such adjustments could be material. See Note 14—Income Taxes of theCombined 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 andrecord liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amounts recordedmay differ from the actual expense incurred when the uncertainty is resolved. The estimates that the Registrants make in accounting for losscontingencies and the actual results that they record upon the ultimate resolution of these uncertainties could have a significant effect on theirconsolidated financial statements. Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sitesfor 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 withother 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 amanner different from the estimate, could have a significant effect on the Registrants’ results of operations, financial position and cash flows. SeeNote 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 Registrantshave reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based onactuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the averagecost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures couldcause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, couldhave 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 andretail); the sale and delivery of electricity and natural gas in regulated markets; and the provision of other energy-related non-regulated productsand services. The appropriate accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable accountingstandards. 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 isdelivered to customers. The Registrants generally use accrual accounting to recognize revenues for sales of electricity, natural gas, and othercommodities 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 121Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsnormal purchases and normal sales (NPNS) of commodities that will be physically delivered, sales to utility customers under regulated servicetariffs, 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 fortransactions 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 andexpenses include: inception gains or losses on new transactions where the fair value is observable and realized; and unrealized gains and lossesfrom 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 oncommon 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 basedon systematic readings of customer meters generally on a monthly basis. At the end of each month, amounts of energy delivered to customerssince the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue isaffected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses ofenergy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers andfavorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation ofunbilled revenue. In addition, volumes may fluctuate monthly as a result of customers electing to use an alternate supplier, which could besignificant to the calculation of unbilled revenue since unbilled commodity receivables are not recorded for these customers. Changes in the timingof meter reading schedules and the number and type of customers scheduled for each meter reading date would also have an effect on themeasurement 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 thedistribution revenue requirement. As of the balance sheet dates, ComEd has recorded its best estimates of the distribution revenue impactresulting 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 andassociated 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. Asof the balance sheet dates, ComEd and BGE have recorded the best estimate of their respective transmission revenue impact resulting fromchanges in rates that ComEd and BGE believe are probable of approval by FERC in accordance with the formula rate mechanism. Estimates arebased upon actual costs incurred and investments in rate base for the period and the rates of return on common equity and associated regulatorycapital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costsincurred and investments made and actions by regulators or courts. 122Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAllowance 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. ForGeneration, the allowance is based on accounts receivable aging historical experience and other currently available information. ComEd andPECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each companyto the outstanding receivable balance by customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accountson customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progressionwhich determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance foruncollectible accounts, which was consistent with ComEd and PECO, as described above. Risk segments represent a group of customers withsimilar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Lossrates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risksegment. ComEd, PECO and BGE customers’ accounts are generally considered delinquent if the amount billed is not received by the time thenext bill is issued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent withapproved regulatory requirements. ComEd’s, PECO’s and BGE’s provisions for uncollectible accounts will continue to be affected by changes involume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 6—AccountsReceivable 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 belowinclude intercompany transactions, which are eliminated in Exelon’s consolidated financial statements. Net Income Attributable to Common Shareholders by Registrant 2014 2013 Favorable(unfavorable)2014 vs. 2013variance 2012 Favorable(unfavorable)2013 vs. 2012variance 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 ofthe 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 fullyconsolidated basis from April 1, 2014, through December 31, 2014. 123 (b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsResults of Operations—Generation 2014 2013 Favorable(unfavorable)2014 vs. 2013variance 2012 Favorable(unfavorable)2013 vs. 2012variance 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 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 purchasedpower 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 andfuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP informationprovided 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 fullyconsolidated basis from April 1, 2014 through December 31, 2014. 124 (c)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsNet Income Attributable to Membership Interest Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Generation’s net income attributable to membership interestdecreased 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’sownership interest in generating stations, the bargain-purchase gain recorded related to the Integrys acquisition, and the gain recorded uponconsolidation of CENG. The increase in operating and maintenance expense was largely due to increased labor contracting and materials expensedue to the inclusion of CENG’s results beginning April 1, 2014 and impairment charges related to 1) generating assets held-for-sale, 2) certainUpstream assets, and 3) wind generating assets. The increase in revenue, net of purchased power and fuel expense was primarily due to theinclusion 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 lowerrealized energy prices related to executing Exelon’s ratable hedging strategy, higher procurement costs for replacement power due to extreme coldweather in the first quarter of 2014, and unrealized mark-to-market losses in 2014. The increase in other income is primarily the result of increasedrealized 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 interestincreased compared to the same period in 2012 primarily due to higher revenue, net of purchased power and fuel expense, lower operating andmaintenance expense and higher earnings from Generation’s interest in CENG; partially offset by impairment of certain generating assets, higherdepreciation expense, higher property taxes, and higher interest expense. The increase in revenue, net of purchased power and fuel expense wasprimarily due to increased capacity prices and higher nuclear volume, partially offset by lower realized energy prices, higher nuclear fuel costs, andlower mark-to-market gains in 2013. The decrease in operating and maintenance expense was largely due to 2012 costs associated with asettlement 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 anISO/RTO and/or NERC region. Descriptions of each of Generation’s six reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, WestVirginia, Delaware, the District of Columbia and parts of North Carolina. • Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky andTennessee, 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. 125Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents • 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 withinMISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, NorthCarolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in theSPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi andArkansas. • 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 ofMISO. The following business activities are not allocated to a region, and are reported under Other: retail and wholesale gas, investments in gasand oil exploration and production activities, proprietary trading, distributed generation, heating, cooling, and cogeneration facilities, and homeimprovements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems andinvestments 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 of2012; unrealized mark-to-market impact of economic hedging activities; amortization of certain intangible assets relating to commodity contractsrecorded 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 netof purchased power and fuel expense which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties andaffiliated sales to ComEd, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricityincluding capacity, energy and ancillary services. Fuel expense includes the fuel costs for internally generated energy and fuel costs associatedwith tolling agreements. 126Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFor the years ended December 31, 2014 compared to 2013 and December 31, 2013 compared to 2012, Generation’s revenue net ofpurchased power and fuel expense by region were as follows: 2014 vs. 2013 2013 vs. 2012 2014 2013 Variance % Change 2012 Variance % Change Mid-Atlantic $3,417 $3,270 $147 4.5% $3,433 $(163) (4.7)% Midwest 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 483 (4) 487 n.m. 76 (80) (105.3)% ERCOT 317 436 (119) (27.3)% 405 31 7.7% Other Regions 327 201 126 62.7% 131 70 53.4% Total electric revenue net of purchased powerand 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 528 263 265 100.8% (364) 627 n.m. Total revenue net of purchased power and fuelexpense $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 fullyconsolidated 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 commoditycontracts 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 yearended 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 endedDecember 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 endedDecember 31, 2012. See Note 25—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information. 127(a) (b)(c)(g) (d) (b)(g) (e) (f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration’s supply sources by region are summarized below: 2014 vs. 2013 2013 vs. 2012 Supply source (GWh) 2014 2013 Variance % Change 2012 Variance % Change Nuclear generation 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 Mid-Atlantic 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 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 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 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 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 Mid-Atlantic 75,916 74,687 1,229 1.6% 76,975 (2,288) (3.0)% Midwest 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 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 thatare 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 NewYork 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 aresult 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 nuclearfleet. 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 fourthquarter 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. 128(a) (b) (b)(b)(d)(e) (c) (c)(e) (f) (g)(h)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsMid-Atlantic Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in revenue net of purchased power and fuelexpense in the Mid-Atlantic of $147 million was primarily due to the consolidation of CENG, the cancellation of the DOE spent nuclear fueldisposal 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 ratablehedging strategy. Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The decrease in revenue net of purchased power and fuelexpense in the Mid-Atlantic of $163 million was primarily due to lower realized energy prices and increased nuclear fuel costs, partially offset bythe 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 fuelexpense in the Midwest of $8 million was primarily due to higher capacity prices, higher nuclear volumes, and the cancellation of the DOE spentnuclear 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 fuelexpense in the Midwest of $412 million was primarily due to lower realized energy prices, increased nuclear fuel costs, and lower capacityrevenues, 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 powerand fuel expense in New England is primarily due to higher realized energy prices and favorable impacts from the restructuring of a fuel supplycontract, 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 powerand fuel expense in New England is primarily due to lower realized energy prices, partially offset by the addition of Constellation in 2012. Prior tothe 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 powerand 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 powerand fuel expense in New York was primarily due to decreased realized energy prices, partially offset by the addition of Constellation. Prior to themerger, New York was not a significant contributor to revenue net of purchased power and fuel expense at Generation. 129Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsERCOT Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The $119 million decrease in revenue net of purchased powerand fuel expense in ERCOT was primarily due to higher procurement costs for replacement power in the second quarter of 2014 and thetermination of an energy supply contract with a retail power supply company that was previously a consolidated variable interest entity. As a resultof the termination, Generation no longer has a variable interest in the retail supply company and ceased consolidation of the entity during the thirdquarter 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 powerand fuel expense in ERCOT was primarily due to increased realized energy prices and the addition of Constellation in 2012, partially offset by adecrease due to the termination of an energy supply contract with a retail power supply company that was previously a consolidated variableinterest entity. As a result of the termination, Generation no longer has a variable interest in the retail supply company and ceased consolidation ofthe 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 powerand 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 powerand 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 withchanges in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market losses on economichedging activities were $591 million in 2014 compared to gains of $504 million in 2013. See Note 11—Fair Value of Financial Assets and Liabilitiesand Note 12—Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains andlosses 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 withchanges in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market gains on economichedging activities were $504 million in 2013 compared to gains of $515 million in 2012. See Note 11—Fair Value of Financial Assets and Liabilitiesand Note 12—Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains andlosses 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 purchasedpower and fuel was primarily due to a reduction in amortization of in-the-money energy contracts recorded at fair value at the Constellation mergerdate and an increase related to the amortization of out-of-the money energy contracts recorded at fair value 130Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsupon 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 purchasedpower and fuel was primarily due to reduced amortization expense of the acquired energy contracts recorded at fair value at the merger date. Inaddition, 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 energyfacilities. These increases were partially offset by the reduction in revenues net of purchased power and fuel expense from the sale of BrandonShores, H.A. Wagner and C.P. Crane, the generating facilities divested in the fourth quarter of 2012 as a result of the Exelon and Constellationmerger. See Note 10—Intangible Assets of the Combined Notes to Consolidated Financial Statements for information regarding contractintangibles 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. Thenuclear 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 theplant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce oneMWh 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 discussedfurther in Note 22—Commitments and Contingencies), and certain other non-production related overhead costs. Generation considers capacityfactor and production costs useful measures to analyze the nuclear fleet performance between periods. Generation has included the analysisbelow as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation definedunder GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere inthis report. 2014 2013 2012 Nuclear fleet capacity factor 94.3% 94.1% 92.7% Nuclear fleet production cost per MWh $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 formore days in 2014. Additionally, with the addition of the CENG nuclear facilities there were more days offline in 2014 associated with units whereExelon’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 toelimination 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 outagedays. For 2013 and 131 (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents2012, planned refueling outage days totaled 233 and 274, respectively, and non-refueling outage days totaled 75 and 73, respectively. Highernuclear fuel costs and higher plant operating and maintenance costs, partially offset by higher number of net MWhs generated resulted in a higherproduction 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) Impairment and related charges of certain generating assets $506 Labor, other benefits, contracting and materials 361 Accretion expense 78 Corporate allocations 69 Regulatory fees and assessments 51 Maryland merger commitments 44 Nuclear refueling outage costs, including the co-owned Salem plant 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 fullyconsolidated 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 during2014.(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 otherbusiness 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. 132 (a)(b)(c)(d)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe changes in operating and maintenance expense for 2013 compared to 2012, consisted of the following: Increase(Decrease) Plant retirements and divestitures $(440) FERC settlement (195) Constellation merger and integration costs (107) Maryland commitments (35) Asbestos bodily injury costs (16) Nuclear refueling outage costs, including the co-owned Salem plant (14) Corporate allocations (5) Labor, other benefits, contracting and materials 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 theimpact 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 wasprimarily due to the inclusion of CENG’s results on a fully consolidated basis beginning April 1, 2014 and an increase in ongoing capitalexpenditures. Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in depreciation and amortization expense wasprimarily 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’sresults 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 ofConstellation’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) ofunconsolidated affiliates is primarily the result of the consolidation of CENG’s results of operations beginning April 1, 2014, which were previouslyaccounted for under the equity method of accounting. 133 (a)(b)(c)(d)(e)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGain (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 assetsreflects $411 million of gains recorded on the sale of Generation’s ownership interests in Safe Harbor Water Power Corporation, Fore River andWest Valley generating stations in 2014. Refer to Note 4—Mergers, Acquisitions and Dispositions in the Combined Notes to ConsolidatedFinancial 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 assetsprimarily 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 ofbusinesses is primarily related to a $261 million gain upon consolidation of CENG resulting from the difference in fair value of CENG’s net assetsas of April 1, 2014 and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existingtransactions 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, 2014compared 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 theincrease 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 offavorable tax settlements related to Constellation’s pre-acquisition 2009-2012 tax returns and the net increase in realized and unrealized gainsrelated 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 expenseassociated with the NDT funds of the Regulatory Agreement Units. Refer to Note 15—Asset Retirement Obligations of the Combined Notes toConsolidated 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 ofcredit 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 $122million 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 CombinedNotes to Consolidated Financial Statements for additional information regarding NDT funds. 134Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized inOther, 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 thecomponents of the effective income tax rates. Results of Operations—ComEd 2014 2013 Favorable(Unfavorable)2014 vs.2013Variance 2012 Favorable(Unfavorable)2013 vs.2012Variance 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 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 auseful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery andtransmission of electricity. ComEd has included its discussion of revenue net of purchased power expense below as a complement to the financial information provided inaccordance 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 135(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsto the 2013 remeasurement of Exelon’s like-kind exchange tax position, and increased electric distribution and transmission earnings resultingfrom 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 unfavorableweather, partially offset by increased electric distribution and transmission earnings resulting from increased costs and capital investments andhigher allowed ROE. See Note 3—Regulatory Matters and Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statementsin 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 commodityprocurement costs and participation in customer choice programs. ComEd is permitted to recover electricity procurement costs from retailcustomers 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 electricityprocurement process. All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs donot impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenue related to supplied energy, which is fully offset in Purchasedpower 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 competitiveelectric generation suppliers represented 80%, 81% and 65% of ComEd’s retail kWh sales for the years ended December 31, 2014, 2013 and2012, respectively. The changes in ComEd’s Revenue net of purchased power expense for the year ended 2014 compared to the same period in 2013 consistedof 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 monthsare referred to as “favorable weather conditions” 136Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsbecause these weather conditions result in increased customer usage. Conversely, mild weather reduces demand. For the year endedDecember 31, 2014, unfavorable weather conditions, primarily during the summer months, reduced Operating revenue net of purchased powerexpense 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 withcooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating andcooling 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 sameperiod 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 theactual costs that the ICC determines are prudently and reasonably incurred in a given year. Under EIMA, distribution revenue varies from year toyear 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 ofplus or minus 50 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on revenue. During the yearended December 31, 2014, distribution revenue decreased $2 million at ComEd, primarily due to lower Operating and maintenance expensesprimarily driven by the impacts of certain OPEB plan design changes, partially offset by increased capital investment. See Operating andMaintenance Expense below, ITEM 1. BUSINESS—Commonwealth Edison Company, Note 3—Regulatory Matters and Note 16—RetirementBenefits 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 yearended December 31, 2014, ComEd recorded increased revenue of $30 million due to increased capital investments. See Note 3—RegulatoryMatters 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 asComEd’s energy efficiency and demand response and purchase power administrative costs. The riders are designed to provide full and currentcost recovery. 137Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe costs of these programs are included in Operating and maintenance expense. Refer to the Operating and maintenance expense discussionbelow 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 maintenanceexpense 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 effectiverates 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 theyear ended December 31, 2014, ComEd recorded $9 million of revenue subject to refund associated with Rider AMP. See Note 3—RegulatoryMatters 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 toother utilities through mutual assistance programs and recoveries of environmental costs associated with MGP sites, recovery of energyprocurement 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 weatherconditions as a result of the mild weather in 2013 compared to the same period in 2012. 138Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe changes in heating and cooling degree days in ComEd’s service territory for the years ended December 31, 2013 and 2012 consisted ofthe 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 yearended 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 increasedcapital investments, increased operating expenses, and higher allowed ROE. These amounts exclude the discrete impacts of the 2012 DistributionRate Case Orders discussed separately below. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements foradditional 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 reestablishedComEd’s position on the return on its pension asset, resulting in an increase to revenue in 2013. See Note 3—Regulatory Matters of the CombinedNotes 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 toConsolidated Financial Statements for additional information. Operating and Maintenance Expense Year EndedDecember 31, Increase Year EndedDecember 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 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 currentbasis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenue. 139 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe changes in Operating and maintenance expense for year ended December 31, 2014, compared to the same period in 2013 and changesfor the year ended December 31, 2013, compared to the same period in 2012, consisted of the following: Increase2014 vs. 2013 Increase2013 vs. 2012 Baseline Labor, other benefits, contracting and materials $56 $48 Pension and non-pension postretirement benefits expense (85) 3 Storm-related costs (11) (10) Uncollectible accounts expense—provision 12 (10) Uncollectible accounts expense—recovery, net 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 theCombined 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 theConsolidated 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 annuallythrough 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 costrecovery and customers purchasing electricity from competitive electric generation suppliers as a result of municipal aggregation. An equal and offsetting reduction has beenrecognized 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: Increase2014 vs. 2013 Increase2013 vs. 2012 Depreciation associated with higher plant balances $46 $22 Amortization of storm-related regulatory assets — 4 Amortization of MGP regulatory assets (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 twelvemonths ended December 31, 2014, compared to the same periods in 2013. 140(a)(b)(c)(c) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsYear Ended December 31, 2013 Compared to Year Ended December 31, 2012. Taxes other than income taxes increased primarily due toincreased 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 $(275) $281 Interest expense on debt (including financing trusts) 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 ConsolidatedFinancial 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 Statementsfor 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 $— $(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 (a) (b) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsEffective 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 ofthe effective income tax rates. ComEd Electric Operating Statistics and Revenue Detail Retail Deliveries to customers (in GWhs) 2014 2013 %Change2014 vs2013 Weather-Normal%Change 2012 %Change2013 vs2012 Weather-Normal%Change Retail Deliveries 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 %Change2014 vs2013 2012 %Change2013vs2012 Retail Sales 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 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 generationsupplier, 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, assistanceprovided to other utilities through mutual assistance programs, recoveries of environmental remediation costs associated with MGP sites, and intercompany revenue. 142 (a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsResults of Operations—PECO 2014 2013 Favorable(unfavorable)2014 vs. 2013variance 2012 Favorable(unfavorable)2013 vs. 2012variance 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 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 thatcan 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 othercompanies’ 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 commonshareholder was driven primarily by an increase in Operating and maintenance expense partially offset by an increase in Operating revenue net ofpurchase 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 lowerOperating and maintenance expense partially offset by an increase in income taxes. 143(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOperating 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’selectric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refundthe difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC’s GSAand PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and gas revenuenet 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 ChoiceProgram. 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 tosupplied energy and natural gas service. Customer Choice Program activity has no impact on electric and gas revenue net of purchase power andfuel expense. The number of retail customers purchasing energy from a competitive electric generation supplier was 546,900, 531,500, and496,500 at December 31, 2014, 2013 and 2012, respectively. Retail deliveries purchased from competitive electric generation suppliersrepresented 70%, 68%, and 66% of PECO’s retail kWh sales for the years ended December 31, 2014, 2013 and 2012, respectively. The number ofretail customers purchasing natural gas from a competitive natural gas supplier was 78,400, 66,400, and 52,700 at December 31, 2014, 2013 and2012, respectively. Retail deliveries purchased from competitive natural gas suppliers represented 22%, 19%, and 16% of PECO’s mmcf sales forthe 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 thesame 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 summermonths 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. Operatingrevenue 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. 144Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsHeating 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. Thechanges in heating and cooling degree days in PECO’s service territory for the year ended December 31, 2014 compared to the same period in2013 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 forgas and residential electric and a shift in the volume profile across classes from commercial and industrial classes to residential classes forelectric. 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 toincreased 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 assmart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs ofthese programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes. Refer to theOperating 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 thesame 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. 145Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe changes in heating and cooling degree days in PECO’s service territory for the year ended December 31, 2013 compared to the sameperiod in 2012 and normal weather consisted of the following: Twelve Months EndedDecember 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, reflectedthe impact of energy efficiency initiatives on customer usages as well as a shift in the volume profile across classes from residential classes tocommercial and industrial classes, partially offset by the oil refineries returning to full production in 2013 as well as moderate economicgrowth. The decrease in gas revenue net of fuel expense related to delivery volume, exclusive of the effects of weather, primarily reflected adecline 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 overalleffective 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, energyefficiency and consumer education programs as well as the administrative costs for the GSA and AEPS programs. The riders are designed toprovide full and current cost recovery as well as a return. The offsetting costs of these programs are included in Operating and maintenanceexpense, Depreciation and amortization expense and Income taxes. Refer to the Operating and maintenance expense discussion below foradditional 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 andoffsetting 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 taxyear. There is an equal and offsetting tax benefit in Operating revenue, see Note 3—Regulatory Matters of the Combined Notes to ConsolidatedFinancial 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 adecrease in wholesale transmission revenue earned by PECO due to higher peak loads in the previous years. 146Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOperating and Maintenance Expense Twelve MonthsEnded December 31, Increase Twelve MonthsEnded 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 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 fulland 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 (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, netfor 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, netfor 2013 compared to 2012 was primarily due to ongoing capital expenditures. 147 (a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTaxes 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 comparedto 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 to2012 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 incometax rates. PECO Electric Operating Statistics and Revenue Detail Retail Deliveries to customers (in GWhs) 2014 2013 % Change2014 vs. 2013 Weather-Normal %Change 2012 % Change2013 vs. 2012 Weather-Normal %Change Retail Deliveries 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(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsElectric Revenue 2014 2013 % Change2014 vs. 2013 2012 % Change2013 vs. 2012 Retail Sales 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 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 supplieras 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 % Change2014 vs. 2013 Weather-Normal %Change 2012 % Change2013 vs. 2012 Weather-Normal %Change Retail Deliveries 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 % Change2014 vs. 2013 2012 % Change2013 vs. 2012 Retail Sales 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 asall customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflect the cost of natural gas. 149(a) (b)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsResults of Operations—BGE 2014 2013 Favorable(unfavorable)2014 vs. 2013variance 2012 Favorable(unfavorable)2013 vs. 2012variance 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 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. BGEbelieves 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 netrevenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net ofpurchased 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 theGAAP 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 remainedrelatively consistent primarily due to an increase in Revenue net of purchased power and fuel expense as a result of the December 2013 and 2014electric and gas distribution rate order issued by the MDPSC offset by increases in Operating and maintenance expense and Depreciationexpense. Year Ended December 31, 2013 Compared to Year Ended December 31, 2012. The increase in Net income was driven primarily by higherdistribution rates as a result of the 2012 rate order issued by MDPSC and decreased Revenue net of purchased power and fuel expense in 2012related to the accrual of the residential customer rate credit provided as a condition of the MDPSC’s approval of Exelon’s merger withConstellation. Additionally, the increase in Net income was also driven by higher Operating and maintenance expenses in 2012, primarily related toBGE’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 stormrestoration costs in 2013. 150(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOperating 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 ascommodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Electric and gas revenueand Purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas ratescharged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost ofpurchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS andgas commodity programs, respectively. The number of customers electing to select a competitive electric generation supplier affects electric SOS revenue and purchased powerexpense. The number of customers electing to select a competitive natural gas supplier affects gas cost adjustment revenue and purchasednatural gas expense. All BGE customers have the choice to purchase energy from a competitive electric generation supplier. This customerchoice of electric generation suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to SOS. Thenumber of retail customers purchasing electricity from a competitive electric generation supplier was 364,000, 399,000 and 362,000 atDecember 31, 2014, 2013 and 2012, respectively, representing 29%, 32% and 29% of total retail customers, respectively. Retail deliveriespurchased from competitive electric generation suppliers represented 60%, 61% and 60% of BGE’s retail kWh sales for the years endedDecember 31, 2014, 2013 and 2012, respectively. The number of retail customers purchasing natural gas from a competitive natural gas supplierwas 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 forthe 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 thesame 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 monthlyadjustment to its electric and gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrialelectric customers, and all firm service gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’selectric 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 whatBGE’s actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth, they will not be affectedby actual weather or usage conditions. BGE bills or credits impacted customers in subsequent months for the difference between approvedrevenue levels under revenue decoupling and actual customer billings. 151Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsHeating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat a home or business. Normalweather is determined based on historical average heating and cooling degree days for a 30-year period in BGE’s service territory. The changes inheating degree days in BGE’s service territory for the year ended December 31, 2014 compared to the same period in 2013 and normal weatherconsisted of the following: Twelve Months EndedDecember 31, Normal % Change Heating and Cooling Degree-Days 2014 2013 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 effectiveDecember 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, 2014compared to the same period in 2013 was primarily due the higher gas margins earned due to extreme cold weather during the first quarter of 2014under BGE’s market-based rate incentive mechanism. See Note 12—Derivative Financial Instruments of the Combined Notes to the ConsolidatedFinancial 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 demandresponse programs as well as administrative and commercial and industrial customer bad debt costs for SOS. The riders are designed to providefull 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 tothe impact of new transmission rates charged to customers that became effective in June 2014. See Note 3—Regulatory Matters of the CombinedNotes 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 varyfrom period to period, includes miscellaneous revenue such as service application and late payment fees. 152Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe changes in BGE’s Revenue net of purchased power and fuel expense for the year ended December 31, 2013 compared to the sameperiod 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 EndedDecember 31, Normal % Change Heating and Cooling Degree-Days 2013 2012 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 in2012 was due to the residential customer rate credit provided in 2012 as a result of the MDPSC’s order approving Exelon’s merger withConstellation. 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 approvingincreases to electric and natural gas distribution rates charged to customers. See Note 3—Regulatory Matters of the Combined Notes to theConsolidated 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 demandresponse programs as well as administrative and commercial and industrial customer bad debt costs for SOS. The riders are designed to providefull 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, 2013compared 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 varyfrom period to period, includes miscellaneous revenue such as service application and late payment fees. 153 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOperating 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 21 (62) Uncollectible accounts expense 17 — Merger transaction costs 5 (21) Charitable contributions — (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, BGEincurred $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 millionof 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 andmerger 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 $25 $18 Regulatory asset amortization (1) 31 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 responseprograms 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(a)(b)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsInterest Expense, Net Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The decrease in Interest expense, net for 2014 compared to2013 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 to2012 was primarily due to interest recorded in 2012 on prior year tax liabilities and lower effective interest rates as a result of the refinancing ofdebt 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. SeeNote 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of theeffective income tax rates. BGE Electric Operating Statistics and Revenue Detail Retail Deliveries to customers (in GWhs) 2014 2013 % Change2014 vs. 2013 Weather-Normal %Change 2012 % Change2013 vs. 2012 Weather-Normal %Change Retail Deliveries 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 % Change2014 vs. 2013 2012 % Change2013 vs. 2012 Retail Sales 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 supplieras all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission. 155(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBGE Gas Operating Statistics and Revenue Detail Deliveries to customers (in mmcf) 2014 2013 % Change2014 vs. 2013 Weather-Normal %Change 2012 % Change2013 vs. 2012 Weather-Normal %Change Retail Deliveries Retail sales 99,194 94,020 5.5% n.m. 86,946 8.1% n.m. Transportation and other 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 % Change2014 vs. 2013 2012 % Change2013 vs. 2012 Retail Sales Retail sales $622 $592 5.1% $494 19.8% Transportation and other 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 asall 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 ended2014, 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 asfunds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and requireconsiderable capital resources. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and currentoverall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that theRegistrants no longer have access to the capital markets at reasonable terms, Exelon, Generation, ComEd, PECO and BGE have access tounsecured 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 withbanks which have various expirations between October 2015 and January 2017. The Registrants utilize their credit facilities to support theircommercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for furtherdiscussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements. 156 (d) (e)(d) (e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retiredebt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend asignificant 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 wheresuch 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 theRegistrants’ 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 tocustomers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and itsability 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, inthe case of PECO and BGE, gas distribution services. ComEd’s, PECO’s and BGE’s distribution services are provided to an established anddiverse base of retail customers. ComEd’s, PECO’s and BGE’s future cash flows may be affected by the economy, weather conditions, futurelegislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieveoperating cost reductions. See Notes 3—Regulatory Matters and 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statementsfor 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 contributionrequirements 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 forProgress in the Twenty-first Century Act, which contains a pension funding provision that results in lower pension contributions in the near termwhile increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law were applied in 2012while others took effect in 2013. On August 8, 2014, this funding relief was extended for five years. The estimated impacts of the law are reflectedin 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’sexpected qualified pension plan contributions above include $36 million related to legacy CENG plans that will be funded by CENG as provided inan Employee Matters Agreement (EMA) between Exelon and CENG. Unlike the qualified pension plans, Exelon’s non-qualified pension plans arenot funded. Exelon expects to make non-qualified pension plan benefit payments of $15 million in 2015, of which Generation, ComEd, PECO andBGE will make payments of $6 million, $1 million, $1 million, and $1 million respectively. See Note 16—Retirement Benefits of the CombinedNotes to Consolidated Financial Statements for the Registrants’ 2014 and 2013 pension contributions. 157Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTo the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contributionrequirements in future years could increase, especially in years 2017 and beyond. Additionally, the contributions above could change if Exelonchanges its pension funding strategy. Unlike qualified pension plans, other postretirement benefit plans are not subject to statutory minimum contribution requirements and certainplans are not funded. Exelon’s management has historically considered several factors in determining the level of contributions to its funded otherpostretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatorexpectations and best assure continued recovery). Exelon expects to make other postretirement benefit plan contributions, including benefitpayments related to unfunded plans, of approximately $37 million in 2015, of which Generation, ComEd, PECO, and BGE expect to contribute $17million, $2 million, $0 million, and $17 million, respectively. See Note 16—Retirement Benefits of the Combined Notes to Consolidated FinancialStatements 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 whichapproximately $310 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless, and thebalance at Exelon. Litigation could take several years such that the estimated cash and interest impacts will increase by a materialamount. • 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 increasethe risk of additional income tax levies, property taxes and other taxes. • On December 19, 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 areestimated 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 thatRegistrants would have received over the normal depreciable life of the property. Furthermore, the extension of 50% bonus depreciationwill result in a decrease to Generation’s Domestic Production Activities Deduction, reducing cash tax benefits and increasing income taxexpense by approximately $30 million for 2014. ComEd’s 2014 revenue requirement is expected to decrease by approximately $12million (after-tax) due to the extension of 50% bonus depreciation. 158thSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThe 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. 2013Variance 2012 (c) 2013 vs. 2012Variance Net income $1,820 $1,729 $91 1,171 $558 Add (subtract): Non-cash operating activities 5,884 4,159 1,725 5,588 (1,429) Pension and non-pension postretirement benefitcontributions (617) (422) (195) (462) 40 Income taxes (143) 883 (1,026) 544 339 Changes in working capital and other noncurrent assetsand liabilities (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, pensionand non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensationexpense, 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 $4,457 $6,343 $6,131 Generation 1,826 3,887 3,581 ComEd 1,326 1,218 1,334 PECO 712 747 878 BGE 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 throughDecember 31, 2012. BGE’s 2012 activity includes its activity for the twelve months ended December 31, 2012. 159(a)(b)(a)(b)(a)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsChanges in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s cash flows from operations were generally consistent with changes ineach Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except asdiscussed 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 orcollected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether thetransactions 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) eachyear were primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position. In addition, in 2014the 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-termborrowings and short-term debt due within one year in 2013. Cash flows from operating activities are sufficient to meet operatingrequirements; however, increased capital investment in infrastructure improvements and modernization pursuant to EIMA, transmissionupgrades 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 2012ComEd’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) millionand $17 million, respectively, and payables to other energy suppliers for energy purchases increased/(decreased) by $10 million, $39million 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. 160Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCash 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 $(4,599) $(5,394) $(4,576) Generation (1,767) (2,916) (2,629) ComEd (1,655) (1,387) (1,212) PECO (649) (531) (328) BGE (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 throughDecember 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 inGeneration’s cash flows from investing activities above. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of the CombinedNotes 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 theSusquehanna River in Pennsylvania for a purchase price of approximately $615 million during the third quarter of 2014. The proceeds from the saleare reflected in Generation’s cash flows from investing activities above. See Note 4—Mergers, Acquisitions, and Dispositions of the CombinedNotes 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 reflectedin Generation’s cash flows from investing activities above. See Note 13—Debt and Credit Agreements of the Combined Notes to ConsolidatedFinancial 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 andrelated equity interests in Keystone Fuels, LLC and Conemaugh Fuels, LLC, respectively, for a purchase price of approximately $473 million duringthe 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 generatingstations, for a combined purchase price of approximately $577 million. The proceeds from the sale are reflected in Generation’s cash flows frominvesting activities above. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements forfurther information. During the fourth quarter of 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys EnergyGroup, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. for a purchase price of $332million, 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. 161(a)(b)(a)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration has entered into several agreements to acquire equity interests in privately held and development stage entities which developenergy-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 Marylandand a new biomass-fueled cogeneration facility in Georgia. The total estimated expenditures for these projects are approximately $1.8 billion andachievement 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: Projected2015 2014 2013 2012 Exelon $7,200 $6,077 $5,395 $5,789 Generation 3,625 3,012 2,752 3,554 ComEd 2,200 1,689 1,433 1,246 PECO 550 661 537 422 BGE 700 620 587 582 Other 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 tenyear 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 throughDecember 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 conditionsand other factors. In 2014, Exelon and its affiliates initiated a comprehensive project to ensure corporate-wide compliance with Version 5 of the North AmericanElectric 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.5compliance 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 investmentsin 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 withinternally generated funds and borrowings. 162(a)(b)(e)(f)(b)(e)(f)(c) (e)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsComEd, PECO and BGE Approximately 85%, 95% and 96% of the projected 2014 capital expenditures at ComEd, PECO and BGE, respectively, are for continuingprojects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems suchas ComEd’s reliability related investments required under EIMA, and ComEd’s, PECO’s and BGE’s construction commitments under PJM’sRTEP. ComEd’s capital expenditures include smart grid/smart meter technology required under EIMA. PECO’s and BGE’s capital expendituresinclude investments related to their respective smart meter programs. The remaining amounts are for capital additions to support new businessand 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 theirtransmission 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 theassessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted2015 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, includingComEd’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 411 (826) (1,085) Generation (537) (384) (777) ComEd 359 61 (212) PECO (250) (361) (382) BGE (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 throughDecember 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 theRegistrants’ debt issuances and retirements. Debt activity for 2014, 2013 and 2012 by Registrant was as follows: 163 (a)(b)(a)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDuring the year ended December 31, 2014, the following long term debt was issued: Company Type Interest Rate Maturity Amount Use of ProceedsExelon Junior Subordinated Notes 2.50% June 1, 2024 $1,150 Used to finance a portion of theacquisition of PHI and forgeneral corporate purposesGeneration Nuclear Fuel Procurement Contract 3.35% June 30, 2018 38 Used for procurement ofuraniumGeneration ExGen Renewables I NonrecourseDebt LIBOR + 4.25% February 6, 2021 300 Used for general corporatepurposesGeneration ExGen Texas Power NonrecourseDebt LIBOR + 4.75% September 18, 2021 675 Used for general corporatepurposesGeneration Energy Efficiency ProjectFinancing 4.12% December 31, 2015 12 Funding to install energyconservation measures inWashington, DCGeneration AVSR DOE Nonrecourse Debt 2.78 - 3.14% January 5, 2037 126 Used for Antelope Valley solardevelopmentGeneration Nuclear Fuel Procurement Contract 3.25% June 30, 2018 32 Used for procurement ofuraniumComEd First Mortgage Bonds Series 115 2.15% January 15, 2019 300 Used to refinance maturingmortgage bonds and generalcorporate purposesComEd First Mortgage Bonds Series 116 4.70% January 15, 2044 350 Used to refinance maturingmortgage bonds and generalcorporate purposesComEd First Mortgage Bonds Series 117 3.10% November 1, 2024 250 Used to repay commercialpaper and general corporatepurposesPECO First and Refunding MortgageBonds 4.15% October 1, 2044 300 Used to repay at maturity firstand refunding mortgage bondsdue October 1, 2014, andgeneral 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 forwardequity 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. 164(a)(b) (b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOn January 13, 2015, Generation issued $750 million in aggregate principal amount of Senior Notes. The Senior Notes carry an annualinterest rate of 2.950%, payable semi-annually, commencing July 15, 2015 and due January 15, 2020. The proceeds of the Senior Notes will beused 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 ascash flow hedges. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of theanticipated interest payments at this time are probable not to occur. As a result Exelon will reclassify $26 million of deferred losses in AOCI toOther, net in the first quarter of 2015. 165Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDuring the year ended December 31, 2013, the following long term debt was issued: Company Type Interest Rate Maturity Amount Use of ProceedsGeneration CEU Upstream Nonrecourse Debt 2.210 - 2.440% July 22, 2016 $5 Used to fund Upstream gas activitiesGeneration AVSR DOE Nonrecourse Debt 2.535 - 3.353% January 5, 2037 227 Used for Antelope Valley solardevelopmentGeneration Social Security Administration ProjectFinancing 2.93% February 18, 2015 1 Used to install conservationmeasures for the Social SecurityAdministration Headquarters facility inMarylandGeneration Energy Efficiency Project Financing 4.40% August 31, 2014 9 Used for funding to install energyconservation measures in Beckley,West VirginiaGeneration Continental Wind Nonrecourse Debt 6.00% February 28, 2033 613 Used for general corporate purposesComEd First Mortgage Bonds, Series 114 4.60% August 15, 2043 350 Used to repay outstandingcommercial paper obligations and forgeneral corporate purposesPECO First and Refunding Mortgage Bondsdue 1.20% October 15, 2016 300 Used to pay at maturity first andrefunding mortgage bonds dueOctober 15, 2013 and other generalcorporate purposesPECO First and Refunding Mortgage Bonds 4.80% October 15, 2043 250 Used to pay at maturity first andrefunding mortgage bonds dueOctober 15, 2013 and other generalcorporate purposesBGE Notes 3.35% July 1, 2023 300 Used to partially refinance Notes dueJuly 1, 2013 and for general corporatepurposes 166Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDuring the year ended December 31, 2012, the following long term debt was issued: Company Type Interest Rate Maturity Amount Use of ProceedsGeneration CEU Upstream Nonrecourse Debt Variable Rate July 16, 2016 $78 Used to fund Upstream gasactivitiesGeneration AVSR DOE Nonrecourse Debt Fixed Rate January 5, 2037 220 Used for Antelope Valley solardevelopmentGeneration Senior Notes 4.25% June 15, 2022 523 Used for general corporate purposesand issued in connection with theExchange OfferGeneration Senior Notes 5.60% June 15, 2042 788 Used for general corporate purposesand issued in connection with theExchange OfferGeneration Constellation Solar HorizonsNonrecourse Debt 2.50% June 7, 2030 38 Used for funding for Maryland solardevelopmentComEd First Mortgage Bonds, Series 113 3.80% October 1, 2042 350 Used to repay outstandingcommercial paper obligations andfor general corporate purposesPECO First and Refunding Mortgage Bonds 2.38% September 15, 2022 350 Used to pay at maturity FirstMortgage Bonds due October 1,2012 and for general corporatepurposesBGE Notes 2.80% August 15, 2022 250 Used to repay total outstandingcommercial paper obligations andfor general corporate purposes 167Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDuring 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 6.00% February 28, 2033 20 Generation Kennett Square Capital Lease 7.83% September 20, 2020 3 Generation ExGen Renewables I Nonrecourse Debt LIBOR + 4.25% February 6, 2021 18 Generation ExGen Texas Power Nonrecourse Debt LIBOR + 4.75% September 18, 2021 2 Generation AVSR DOE Nonrecourse Debt 2.33% - 3.55% January 5, 2037 15 Generation Constellation Solar Horizons Nonrecourse Debt 2.56% September 7, 2030 2 Generation Sacramento PV Energy Nonrecourse Debt 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(a)(a)(a)(a)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDuring 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 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 ofGeneration (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting inintercompany 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 atExelon 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’sConsolidated Balance Sheets as of December 31, 2012. The debentures were redeemed and the intercompany loan agreements repaid on June 15, 2013. 169(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDuring 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, openmarket 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 $1,486 $1,249 1,716 Generation 1,066 625 1,626 ComEd 307 220 105 PECO 320 333 347 BGE 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’scommon stock payable on March 10, 2014, to shareholders of record of Exelon at the end of the day on February 14, 2014. 170 (a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSecond 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’scommon 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’scommon 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’scommon 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’scommon 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 $17 $13 $(52) ComEd 120 184 — BGE (15) 135 — Other — — (145) Exelon $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 asfollows: 2014 2013 2012 Generation $53 $26 $48 ComEd 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 supportexpanded capital programs. 171(a) (b)(a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDistributions to Noncontrolling Interests of Consolidated VIE. On April 1, 2014, Generation loaned $400 million to CENG, the proceedsof which were used to make a distribution to EDFI of $400 million. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of theCombined 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 theacquisition of PHI, other project financing and various debt issuance costs. See notes 4, 13, and 19 of the Combined Notes to ConsolidatedFinancial 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 cashflows 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 hasmore than 8% of the aggregate commitments for Exelon, Generation, ComEd, PECO and BGE. The Registrants had access to the commercialpaper market during 2014 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidityposition, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity pricemovements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. TheRegistrants 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 Factorsfor 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 sufficientliquidity. If Generation lost its investment grade credit rating as of December 31, 2014, it would have been required to provide incremental collateralof $2.4 billion of collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables andreceivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacitiesof $4.6 billion. If ComEd lost its investment grade credit ratings as of December 31, 2014, it would have been required to provide incrementalcollateral of $14 million, which is well within its current available credit facility capacity of $998 million. If PECO lost its investment grade creditrating as of December 31, 2014 it would not be required to provide collateral pursuant to PJM’s credit policy and could have been required toprovide collateral of $36 million related to its natural gas procurement contracts, which, in the aggregate, are well within PECO’s current availablecredit facility capacity of $599 million. If BGE lost its investment grade credit rating as of December 31, 2014 it would have been required toprovide collateral of $2 million pursuant to PJM’s credit policy and could have been required to provide collateral of $79 million related to its naturalgas 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. 172Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsOther 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 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 specialpurpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd, PECO and BGE. See Note 2—Variable Interest Entitiesof 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 borrowingparticipants than the cost of external financing, Exelon operates an intercompany money pool. Maximum amounts contributed to and borrowedfrom 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: MaximumContributed MaximumBorrowed December 31, 2014Contributed (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, tofund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to funddecommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of thetrust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’sinvestment policies establishes limits on the concentration of holdings in any one company and also in any one industry. See Note 15—AssetRetirement Obligations of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’sminimum funding requirements and related liquidity ramifications. Shelf Registration Statements. The Registrants maintain a combined shelf registration statement unlimited in amount, with the SEC. Theability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a numberof factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of theRegistrant, 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 authorizationof the ICC, PAPUC and MDPSC, respectively. ComEd, PECO and BGE normally obtain the required approvals on a periodic basis to cover theiranticipated financing needs for a period of time or in connection with a specific financing. As of December 31, 2014, ComEd had $702 millionavailable in long-term debt refinancing authority and 173 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents$943 million available in new money long-term debt financing authority from the ICC. During the fourth quarter of 2014, ComEd requested anextension of the expiration date of the refinancing authority from the ICC. In January 2015, the ICC approved the extension of the refinancingauthority, which now expires on February 27, 2017. As of December 31, 2014, PECO had $1.1 billion available in long-term debt financing authorityfrom 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 ofDecember 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 itsmarket-based rate authority. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additionalinformation. Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The paymentsof 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 anydividends of such public utility from any funds properly included in capital account.” In addition, under Illinois law, ComEd may not pay anydividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision ismade for reasonable and proper reserves, or unless ComEd has specific authorization from the ICC. BGE is subject to certain dividend restrictionsestablished by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE isprohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculatedpursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit ratingagencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to deferinterest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) anydividends (and any redemption payments) due on BGE’s preference stock have not been paid. At December 31, 2014, Exelon had retainedearnings of $10,910 million, including Generation’s undistributed earnings of $3,803 million, ComEd’s retained earnings of $851 million consistingof retained earnings appropriated for future dividends of $2,490 million partially offset by $1,639 million of unappropriated retained deficit, PECO’sretained earnings of $681 million and BGE’s retained earnings $1,203 million. See Note 22—Commitments and Contingencies of the CombinedNotes to Consolidated Financial Statements for additional information regarding fund transfer restrictions. 174Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsContractual Obligations The following tables summarize the Registrants’ future estimated cash payments as of December 31, 2014 under existing contractualobligations, including payments due by period. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated FinancialStatements for information regarding the Registrants’ commercial and other commitments, representing commitments potentially triggered byfuture events. Exelon Payment due within Total 2015 2016-2017 2018-2019 Due 2020and beyond AllOther Long-term debt $21,372 $1,736 $3,661 $2,387 $13,588 $— Interest payments on long-term debt 13,105 922 1,755 1,435 8,993 — Liability and interest for uncertain tax positions 779 — — — — 779 Capital leases 32 3 8 9 12 — Operating leases 1,158 99 204 156 699 — Purchase power obligations 2,084 590 884 295 315 — Fuel purchase agreements 10,020 1,661 2,555 2,048 3,756 — Electric supply procurement 1,510 1,057 453 — — — AEC purchase commitments 8 1 2 2 3 — Curtailment services commitments 115 40 63 12 — — Long-term renewable energy and REC commitments 1,516 75 152 162 1,127 — Other purchase obligations 894 336 408 66 84 — Construction commitments 1,143 43 1,100 — — — PJM regional transmission expansion commitments 786 259 414 113 — — Spent nuclear fuel obligation 1,021 — — — 1,021 — Pension minimum funding requirement 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, earlyredemptions 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 toreasonably 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 oftax 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 cashpayments 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’sexpected payments under these arrangements at December 31, 2014, including those related to CENG. Expected payments include certain fixed capacity charges which may bereduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. These obligations do not include ComEd’s SFCs as thesecontracts do not require purchases of fixed or minimum quantities. See Notes 3—Regulatory Matters and 22—Commitments and Contingencies of the Combined Notes toConsolidated Financial Statements. 175(a)(b)(c)(d)(e)(f)(f)(f)(f)(g)(h)(i)(j)(k)(l)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(f)Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs andcurtailment 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 fromretail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note3—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 andContingencies 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—Commitmentsand 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 amountsrepresent 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 ofCombined 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 fundingstrategy 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 avoidbenefit restrictions and at-risk status thereafter. The remaining qualified pension plans’ contributions are generally based on the estimated minimum pension contributions requiredunder 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 thatare 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 theCombined 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 2020and beyond AllOther Long-term debt $8,110 $601 $701 $747 $6,061 $— Interest payments on long-term debt 5,392 391 772 683 3,546 — Liability and interest for uncertain tax benefits 58 — — — — 58 Capital leases 24 3 8 9 4 — Operating leases 899 51 120 100 628 — Purchase power obligations 2,084 590 884 295 315 — Fuel purchase agreements 8,981 1,404 2,243 1,889 3,445 — Other purchase obligations 396 163 109 54 70 — Construction commitments 1,143 43 1,100 — — — Spent nuclear fuel obligation 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, earlyredemptions 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 toreasonably 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’sexpected payments under these arrangements at December 31, 2014. Expected payments include certain fixed capacity charges which may be reduced based on plantavailability. Expected payments exclude renewable PPA contracts that are contingent in nature. See Note 22—Commitments and Contingencies of the Combined Notes toConsolidated Financial Statements. 176 (a)(b) (c) (d) (e)(f)(g)(h)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(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 theCombined 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 investmentsin 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 2020and beyond AllOther Long-term debt $6,175 $260 $1,090 $1,140 $3,685 $— Interest payments on long-term debt 3,882 292 536 379 2,675 — Liability and interest for uncertain tax positions 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 1,517 75 153 162 1,127 — Other purchase obligations 148 63 78 2 5 — PJM regional transmission expansion commitments 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)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2014 and do not reflect anticipated future refinancing, earlyredemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2014. Includes estimated interest payments due to the ComEdfinancing trust.(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 toreasonably 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)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 fromretail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.(e)Represents commitments for services, materials, information technology, and smart meter installation. See Note 22—Commitments and Contingencies of the Combined Notes toConsolidated 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’sexpected portion of the costs to pay for the completion of the required construction projects. See Note 3—Regulatory Matters of Combined Notes to Consolidated FinancialStatements for additional information. 177 (a) (b) (c) (d)(e) (f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO Payment due within Total 2015 2016-2017 2018-2019 Due 2020and beyond AllOther Long-term debt $2,434 $— $300 $500 $1,634 $— Interest payments on long-term debt 1,773 107 210 158 1,298 — Operating leases 14 3 6 5 — — Fuel purchase agreements 428 146 163 48 71 — Electric supply procurement 609 527 82 — — — AEC purchase commitments 13 2 4 4 3 — Other purchase obligations 7 3 4 — — — PJM regional transmission expansion commitments 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, earlyredemptions 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 toConsolidated 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 expectedportion 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 foradditional information. BGE Payment due within Total 2015 2016-2017 2018-2019 Due 2020and beyond AllOther Long-term debt $2,203 $75 $420 $— $1,708 $— Interest payments on long-term debt 1,477 104 181 159 1,033 — Liability and interest for uncertain tax positions 1 — — — — 1 Operating leases 77 13 21 16 27 — Fuel purchase agreements 611 111 149 111 240 — Electric supply procurement 1,315 779 536 — — — Curtailment services commitments 115 40 63 12 — — Other purchase obligations 343 107 217 10 9 — PJM regional transmission expansion commitments 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, earlyredemptions 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 yearsbeyond 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. 178 (a) (b) (c) (c) (c)(d) (e) (a) (b)(c) (d) (d) (d)(e) (f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(e)Represents commitments for services, materials, information technology, and smart meter installation. See Note 22—Commitments and Contingencies of the Combined Notes toConsolidated 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 expectedportion 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 theRegistrants’ 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 andContingencies 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 FinancialStatements. 179Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 andequity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty creditapproval, 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 ofConstellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk managementactivities. 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, weatherconditions, governmental regulatory and environmental policies, and other factors. To the extent the amount of energy Exelon generates differsfrom the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Exelon seeks to mitigate itscommodity 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 ofGeneration’s obligations to customers, including portions of ComEd’s, PECO’s and BGE’s retail load, is sold into the wholesale markets. Toreduce 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 representeconomic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economichedges 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 andcontracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over the three years leading tothe 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 salesdivided by the expected generation (which reflects the divestiture impact of Quail Run). Expected generation is the volume of energy that bestrepresents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makesassumptions 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 FinancialStatements 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 fuelprices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecastedmarket price risk exposure for Generation’s entire non-trading portfolio associated with a $5 reduction in the annual average around-the-clockenergy price based on December 31, 2014, market conditions and hedged position would be a decrease in pre-tax net income of approximately $10million, $350 million and $670 million, respectively, for 2015, 2016 and 2017. Power price sensitivities are derived by 180Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsadjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigatemarket price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, pricechanges, as well as future changes in Generation’s portfolio. Proprietary Trading Activities. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietarytrading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into withthe intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary tradingportfolio 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 ofthe proprietary trading activities. The proprietary trading activities, which included physical volumes of 10,571 GWh, 8,762 GWh, and 12,958 GWhfor the years ended December 31, 2014, 2013 and 2012 respectively, are a complement to Generation’s energy marketing portfolio, but represent asmall 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 dailyVaR on proprietary trading activity averaged $0.4 million of exposure during the year. Generation has not segregated proprietary trading activitywithin the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin fromcontinuing 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 conversionservices, enrichment services and fuel fabrication services. The supply markets for coal, natural gas, uranium concentrates and certain nuclearfuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contractssubject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contractedprices. Approximately 50% of Generation’s uranium concentrate requirements from 2015 through 2019 are supplied by three producers. In theevent of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although atprices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties couldhave a material impact on Exelon’s and Generation’s results of operations, cash flows and financial positions. See Note 22—Commitments andContingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supplyagreement matters. ComEd The financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby ensuringthat 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 toa regulatory asset or liability. This financial swap contract between Generation and ComEd expired on May 31, 2013. All realized impacts havebeen 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 renewableenergy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers forrenewable 181Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsenergy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under theexisting long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and theamount of the reduction was approved by the ICC in March 2014. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instrumentsof 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 FinancialStatements. PECO has certain full requirements contracts and block contracts, which are considered derivatives and qualify for the normalpurchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basisof 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 orhave no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’shedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fullyrecovered from customers under the PGC. PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note12—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 SOSprogram. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exceptionunder current derivative authoritative guidance and as a result, are accounted for on an accrual basis of accounting. Under the SOS program, BGEis permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder returncomponent and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for theresidential 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, tohedge 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 themarket price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholdersand customers. BGE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements. 182Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsTrading 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 includedto 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 liabilitybalance sheet position from January 1, 2013 to December 31, 2014. It indicates the drivers behind changes in the balance sheet amounts. Thistable incorporates the mark-to-market activities that are immediately recorded in earnings, as well as the settlements from OCI to earnings andchanges in fair value for the cash flow hedging activities that are recorded in Accumulated OCI on the Consolidated Balance Sheets. This tableexcludes all normal purchase and normal sales contracts and does not segregate proprietary trading activity. See Note 12—Derivative FinancialInstruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of themark-to-market energy contract net assets (liabilities) recorded as of December 31, 2014 and December 31, 2013. Generation ComEd Intercompany Eliminations Exelon Total mark-to-market energy contract net assets (liabilities) at January 1, 2013 $1,505 $(293) $— $1,212 Total change in fair value during 2013 of contracts recorded in result ofoperations 444 — (6) 438 Reclassification to realized at settlement of contracts recorded in results ofoperations 25 — 13 38 Reclassification to realized at settlement from accumulated OCI (683) — 219 (464) Changes in fair value—energy derivatives — 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 1,047 $(193) $— 854 Contracts acquired at merger date 128 128 Total change in fair value during 2014 of contracts recorded in result ofoperations (608) — — (608) Reclassification to realized at settlement of contracts recorded in results ofoperations (21) — — (21) Reclassification to realized at settlement from accumulated OCI (195) — — (195) Changes in fair value—energy derivatives — (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 $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 swapcontract with ComEd for the year ended December 31, 2013. 183 (b)(a)(c)(d)(a)(e)(d)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents(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 $11million 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-yearfinancial 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 netassets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determiningthe carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show thematurity, 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 CombinedNotes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy. Exelon Maturities Within Total FairValue 2015 2016 2017 2018 2019 2020 andBeyond Normal Operations, Commodity derivative contracts : 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) 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. 184(a)(b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration Maturities Within Total FairValue 2015 2016 2017 2018 2019 2020 andBeyond Normal Operations, Commodity derivative contracts : 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 FairValue 2015 2016 2017 2018 2019 2020 andBeyond Prices based on model or other valuation methods (Level 3) $(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) The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivativeinstruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. SeeNote 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk,collateral, and contingent related features. 185(a)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGeneration The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal salesagreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as ofDecember 31, 2014. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration ofcredit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figuresin 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 exposureswith 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 TotalExposureBefore CreditCollateral Credit Collateral NetExposure Number ofCounterpartiesGreater than 10%of Net Exposure Net Exposure ofCounterpartiesGreater 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-investmentgrade 60 4 56 — — Total $2,217 $85 $2,132 1 $452 Maturity of Credit Risk Exposure Rating as of December 31, 2014 Less than2 Years 2-5Years ExposureGreater than5 Years Total ExposureBefore CreditCollateral 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 ofDecember 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. 186(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsComEd Credit risk for ComEd is managed by credit and collection policies, which are consistent with state regulatory requirements. ComEd iscurrently 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 AccountingPolicies of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. ComEd is permitted torecover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd willmonitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. The Illinois SettlementLegislation prohibits utilities, including ComEd, from terminating electric service to a residential electric space heat customer due to nonpaymentbetween December 1 of any year through March 1 of the following year. ComEd’s ability to disconnect non space-heating residential customers isalso impacted by certain weather restrictions, at any time of year, under the Illinois Public Utilities Act. ComEd will monitor the impact of itsdisconnection practices and will make any necessary adjustments to the provision for uncollectible accounts. ComEd did not have any customersrepresenting over 10% of its revenues as of December 31, 2014. See Note 3—Regulatory Matters of the Combined Notes to ConsolidatedFinancial Statements for additional information regarding ComEd’s recently approved tariffs to adjust rates annually through a rider mechanism toreflect 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 forwardmarket prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term andare set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to postcollateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecuredcredit used by the suppliers represents ComEd’s net credit exposure. ComEd’s counterparty credit risk is mitigated by its ability to recoverrealized 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 currentlyobligated to provide service to all retail electric customers within its franchised territory. PECO records a provision for uncollectible accounts toprovide for the potential loss from nonpayment by these customers. See Note 1—Significant Accounting Policies of the Combined Notes toConsolidated Financial Statements for the allowance for uncollectible accounts policy. In accordance with PAPUC regulations, after November 30and before April 1, an electric distribution utility or natural gas distribution utility shall not terminate service to customers with household incomesat or below 250% of the Federal poverty level. PECO’s provision for uncollectible accounts will continue to be affected by changes in prices aswell 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 assurancerequirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit isdetermined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The creditposition is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the currentforward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to postcollateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2014, PECO had no net creditexposure with suppliers. 187Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO 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 currentlyobligated to provide service to all electric customers within its franchised territory. BGE records a provision for uncollectible accounts to providefor the potential loss from nonpayment by these customers. BGE will monitor nonpayment from customers and will make any necessaryadjustments to the provision for uncollectible accounts. See Note 1—Significant Accounting Policies of the Combined Notes to ConsolidatedFinancial Statements for uncollectible accounts policy. MDPSC regulations prohibit BGE from terminating service to residential customers due tononpayment from November 1 through March 31 if the forecasted temperature is 32 degrees or below for the subsequent 72 hour period. BGE isalso prohibited by the Public Utilities Article of the Annotated Code of Maryland and MDPSC regulations from terminating service to residentialcustomers due to nonpayment if the forecasted temperature is 95 degrees or above for the subsequent 72 hour period. BGE did not have anycustomers 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 definea supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount ofunsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agenciesand the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is theforward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forwardprice curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater thanthe supplier’s unsecured credit limit. The seller’s credit exposure is calculated each business day. As of December 31, 2014, BGE had no netcredit 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 procurenatural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied itscustomers’ demands, which are not covered by the gas cost adjustment clause. At December 31, 2014, BGE had credit exposure of $8 millionrelated to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with thosethird-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 ofelectricity, fossil fuel and other commodities. These contracts either contain express provisions or otherwise permit Generation and itscounterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with thecontracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investmentgrade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance offuture performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absenceof expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and 188Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentscircumstances 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 intothe disclosure below. See Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for informationregarding collateral requirements. Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability ofcounterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a materialimpact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above or fall below contractedprice levels, Generation or its counterparties may be required to post collateral with one another. In order to post collateral, Generation depends onaccess to bank credit facilities which serve as liquidity sources to fund collateral requirements. See Note 13—Debt and Credit Agreements of theCombined 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 counterpartieswith derivative positions, of which $1,406 million and $6 million in net cash collateral deposits were offset against energy mark-to-market andinterest 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 oras of the balance sheet date there were no positions to offset. As of December 31, 2013, Generation had cash collateral posted of $72 million andcash collateral held of $206 million for counterparties with derivative positions, of which $144 million in net cash collateral deposits were offsetagainst 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 tooffset. See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding theletters 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 contractsand held approximately $19 million in the form of cash for both annual and long-term renewable energy contracts. See Note 3—Regulatory Mattersand 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 collateralunder its natural gas procurement contracts nor was it holding collateral under its electric supply and natural gas procurement contracts. See Note12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. 189Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsRTOs 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 buyersand 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 ispurchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISOmaintains 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 remainingparticipants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results ofoperations, 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 exchangeclearinghouses act as the counterparty to each trade. Transactions on the NYMEX, ICE and Nodal exchange must adhere to comprehensivecollateral and margining requirements. As a result, transactions on NYMEX, ICE and Nodal exchange are significantly collateralized and havelimited counterparty credit risk. In 2014 the exchanges increased initial margin rates, which required Generation to post higher amounts of initialmargin collateral. Generation believes that increased market volatility and extreme weather events, such as the Polar Vortex, contributed to therate 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 Georgiasubject 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 leaseterms. If the lessee does not exercise the fixed purchase options, Exelon has the ability to operate the stations and keep or market the poweritself 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 toresidual value risk if the lessee does not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduledpayments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than theexpected remaining useful life of the plants and, therefore, Exelon’s exposure to residual value risk will not be mitigated by payments under theservice contract in this remaining period. Lessee performance under the lease agreements is supported by collateral and credit enhancementmeasures. Management regularly evaluates the creditworthiness of Exelon’s counterparties to these long-term leases. Exelon monitors thecontinuing 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 along-term lease. In February 2014, Exelon and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate theleases prior to their expiration dates. As a result of the lease termination, Exelon received a net early termination amount of $335 million from CPSand 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 Taxesof 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 leaseinvestments at least annually and, if the review indicates a 190Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsfair value below the carrying value and the decline is determined to be other than temporary, must record an impairment charge in the period theestimate changed. Based on the annual reviews performed in 2014 and 2013, the estimated residual value of Exelon’s direct financing leases forthe Georgia generating stations experienced other than temporary declines given reduced long-term energy and capacity price expectations. As aresult, 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 utilizefixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. Inaddition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designatedas cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2014, Exelon and Generation had $1,450million and $550 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $3,070 million and $770 million of notionalamounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, ahypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floatingswaps would result in approximately a $8 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2014. Tomanage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizesforeign 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 ofsecurities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationaryincreases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and thevalue of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance ofthe trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10% increasein 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 allother variables constant and assumes only the discussed changes in interest rates and equity prices. See ITEM 7. MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of equity price risk as aresult of the current capital and credit market conditions. 191Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 regionsthrough its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation alsosells 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. Thesesegments 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 ANDANALYSIS 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 YearEnded 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 ofOperations—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 providedby 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 atreasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If theseconditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to creditfacilities 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 FinancialStatements 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 ofdistributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could requireexternal financing or borrowings or capital contributions from Exelon. 192Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCash 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 CapitalResources” 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 criticalaccounting policies and estimates. New Accounting Pronouncements See Note 1 of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements. ITEM7A. 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 describedabove under “Quantitative and Qualitative Disclosures about Market Risk—Exelon.” 193Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 theprovision of distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussedin 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 thisForm 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 YearEnded 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 ofOperations—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 byinternally 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 andgeneral business conditions, as well as that of the utility industry in general. At December 31, 2014, ComEd had access to a revolving creditfacility with aggregate bank commitments of $1 billion. See the “Credit Matters” section of “Liquidity and Capital Resources” for additionaldiscussion. See the “EXELON CORPORATION—Liquidity and Capital Resources” and Note 13 of the Combined Notes to Consolidated FinancialStatements 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 toExelon’s pension plans. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may belimited 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. 194Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCash 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 CapitalResources” 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 criticalaccounting 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.” 195Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 theprovision of distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulatedretail sale of natural gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia. Thissegment 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 thisForm 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 YearEnded 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 ofOperations—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 byinternally 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 itscredit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO nolonger has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At December 31, 2014, PECO hadaccess to a revolving credit facility with aggregate bank commitments of $600 million. See the “Credit Matters” section of “Liquidity and CapitalResources” for additional discussion. Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment ofdividends and contributions to Exelon’s pension plans. Additionally, PECO operates in a rate-regulated environment in which the amount of newinvestment 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. 196Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCash 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 CapitalResources” 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 criticalaccounting 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 andQualitative Disclosures about Market Risk—Exelon.” 197Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 theprovision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail saleof natural gas and the provision of distribution service in central Maryland, including the City of Baltimore. This segment is discussed in furtherdetail 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 thisForm 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 YearEnded 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 ofOperations—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 internallygenerated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercialpaper. BGE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as thatof 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 bankcommitments 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 dividendsand contributions to Exelon’s pension plans. Additionally, BGE operates in a rate-regulated environment in which the amount of new investmentrecovery 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. 198Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCash 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 CapitalResources” 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 “ContractualObligations 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 criticalaccounting policies and estimates. New Accounting Pronouncements See Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding newaccounting 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 andQualitative Disclosures about Market Risk—Exelon.” 199Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 financialreporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe 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 ofSponsoring 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 internalcontrol over financial reporting as of December 31, 2014. This exclusion is in accordance with the SEC’s general guidance that an assessment ofa 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 byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 13, 2015 200Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsManagement’s Report on Internal Control Over Financial Reporting The management of Exelon Generation Company, LLC (Generation) is responsible for establishing and maintaining adequate internal controlover financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as ofDecember 31, 2014. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by theCommittee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, asof 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’sinternal control over financial reporting as of December 31, 2014. This exclusion is in accordance with the SEC’s general guidance that anassessment 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 byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 13, 2015 201Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsManagement’s Report on Internal Control Over Financial Reporting The management of Commonwealth Edison Company (ComEd) is responsible for establishing and maintaining adequate internal control overfinancial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as ofDecember 31, 2014. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by theCommittee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ComEd’s management concluded that, as ofDecember 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 byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 13, 2015 202Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsManagement’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 financialreporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. 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 ofSponsoring 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 byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 13, 2015 203Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsManagement’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 controlover financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. 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 ofSponsoring 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 PricewaterhouseCoopersLLP, an independent registered public accounting firm, as stated in their report which appears herein. February 13, 2015 204Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsReport 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 operationsand their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally acceptedin 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 financialstatements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financialstatement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. Ourresponsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal controlover financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained inall material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosuresin the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overallfinancial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control overfinancial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness ofinternal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in thecircumstances. 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 offinancial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Acompany’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directorsof the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition ofthe company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. As described in Management’s Report on Internal Control over Financial Reporting appearing under Item 8, management has excludedIntegrys Energy Services, Inc. (“Integrys”) from its 205Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsassessment of internal control over financial reporting as of December 31, 2014 because it was acquired by the Company in a purchase businesscombination 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 statementamounts as of and for the year ended December 31, 2014. /s/ PricewaterhouseCoopers LLPChicago, IllinoisFebruary 13, 2015 206Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsReport 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 oftheir operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principlesgenerally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing underItem 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financialstatement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal controlover financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. Our responsibility isto express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financialreporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting OversightBoard (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financialstatements 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 financialstatements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financialstatement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal controlbased on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. Webelieve 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 offinancial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Acompany’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directorsof the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition ofthe company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. 207Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAs described in Management’s Report on Internal Control over Financial Reporting appearing under Item 8, management has excludedIntegrys Energy Services, Inc. (“Integrys”) from its assessment of internal control over financial reporting as of December 31, 2014 because it wasacquired by the Company in a purchase business combination on November 1, 2014. We have also excluded Integrys from our audit of internalcontrol 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 LLPBaltimore, MarylandFebruary 13, 2015 208Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsReport 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 oftheir operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principlesgenerally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing underItem 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financialstatement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal controlover financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. Our responsibility isto express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financialreporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting OversightBoard (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financialstatements 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 financialstatements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financialstatement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal controlbased on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. Webelieve 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 offinancial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Acompany’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directorsof the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition ofthe company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. /s/ PricewaterhouseCoopers LLPChicago, IllinoisFebruary 13, 2015 209Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsReport 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 theiroperations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principlesgenerally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing underItem 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financialstatement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal controlover financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. Our responsibility isto express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financialreporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting OversightBoard (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financialstatements 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 financialstatements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financialstatement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal controlbased on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. Webelieve 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 offinancial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Acompany’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directorsof the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition ofthe company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. /s/ PricewaterhouseCoopers LLPPhiladelphia, PennsylvaniaFebruary 13, 2015 210Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsReport 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 resultsof their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principlesgenerally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing underItem 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financialstatement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal controlover financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. Our responsibility isto express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financialreporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting OversightBoard (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financialstatements 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 financialstatements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financialstatement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financialreporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal controlbased on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. Webelieve 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 offinancial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Acompany’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directorsof the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition ofthe company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate. /s/ PricewaterhouseCoopers LLPBaltimore, MarylandFebruary 13, 2015 211Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents [THIS PAGE INTENTIONALLY LEFT BLANK] 212Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Corporation and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years EndedDecember 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 stockdividends 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 213Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Corporation and Subsidiary Companies Consolidated Statements of Cash Flows For the Years EndedDecember 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 energycontract 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 214Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 $86,814 $79,924 See the Combined Notes to Consolidated Financial Statements 215(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 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, 2014and 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 tosettle 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 VIEsfor 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(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Corporation and Subsidiary Companies Consolidated Statements of Changes in Shareholders’ Equity (In millions, shares inthousands) IssuedShares CommonStock TreasuryStock RetainedEarnings AccumulatedOtherComprehensiveLoss Non-controllingInterest PreferredandPreferenceStock TotalShareholders’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 noncontrollinginterest — — — — — (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 incometaxes — — — — 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 uponconsolidation of CENG — — — — — 1,548 — 1,548 Transfer of CENG pension and non-pensionpostretirement benefit obligations — 2 — — — — — 2 Consolidated VIE dividend to noncontrollinginterest — — — — — (421) — (421) Reversal of CENG equity method AOCI, net ofincome 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 217Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents [THIS PAGE INTENTIONALLY LEFT BLANK] 218Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Generation Company, LLC and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years EndedDecember 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 219Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Generation Company, LLC and Subsidiary Companies Consolidated Statements of Cash Flows For the Years EndedDecember 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 contractamortization 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 220Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Generation Company, LLC and Subsidiary Companies Consolidated Balance Sheets (In millions) December 31, 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 $45,348 $41,232 See the Combined Notes to Consolidated Financial Statements 221(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 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 tosettle 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 certainVIEs 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(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Generation Company, LLC and Subsidiary Companies Consolidated Statements of Changes in Member’s Equity (In millions) Member’s Equity NoncontrollingInterest TotalEquity MembershipInterest UndistributedEarnings AccumulatedOtherComprehensiveIncome (loss) 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 223Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents [THIS PAGE INTENTIONALLY LEFT BLANK] 224Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCommonwealth Edison Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years EndedDecember 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 225Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCommonwealth 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 226Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCommonwealth 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 227Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCommonwealth 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 228Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCommonwealth Edison Company and Subsidiary Companies Consolidated Statements of Changes in Shareholders’ Equity (In millions) CommonStock OtherPaid-InCapital Retained DeficitUnappropriated RetainedEarningsAppropriated AccumulatedOtherComprehensiveIncome (Loss) TotalShareholders’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 futuredividends — — (379) 379 — — Other comprehensive income, net of incometaxes 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 futuredividends — — (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 futuredividends — — (408) 408 — — Balance, December 31, 2014 $1,588 $5,468 $(1,639) $2,490 $— $7,907 See the Combined Notes to Consolidated Financial Statements 229Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents [THIS PAGE INTENTIONALLY LEFT BLANK] 230Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO Energy Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years EndedDecember 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 231Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO Energy Company and Subsidiary Companies Consolidated Statements of Cash Flows For the Years EndedDecember 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 benefitcontributions (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 232Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO 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 233Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO 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 234Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO Energy Company and Subsidiary Companies Consolidated Statements of Changes in Stockholders’ Equity (In millions) CommonStock RetainedEarnings AccumulatedOtherComprehensiveIncome TotalShareholders’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 235Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contents [THIS PAGE INTENTIONALLY LEFT BLANK] 236Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBaltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income For the Years EndedDecember 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 237Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBaltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Cash Flows For the Years EndedDecember 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 238Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBaltimore 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 $8,078 $7,861 See the Combined Notes to Consolidated Financial Statements 239 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBaltimore 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 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 tosettle 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’sconsolidated 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 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBaltimore Gas and Electric Company and Subsidiary Companies Consolidated Statement of Changes in Shareholders’ Equity (In millions) CommonStock RetainedEarnings TotalShareholders’Equity Preference stocknot subject tomandatoryredemption TotalEquity 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 241Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 towhich the footnotes apply: Applicable Notes Registrant 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26Exelon 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 distributionbusinesses. Prior to March 12, 2012, Exelon’s principal subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellationmerged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan ofMerger (“Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customersupply 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 andGeneration accounted for CENG as an equity method investment. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC forfurther 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 otherenergy-related products and services, and natural gas exploration and production activities. Generation has six reportable segmentsconsisting 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 southeasternPennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision ofdistribution 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 incentral Maryland, including the City of Baltimore. 242Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Statementsapply 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. Theinformation disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2014, 2013 and 2012 andthe financial position as of December 31, 2014 and December 31, 2013. However, for Exelon’s consolidated financial reporting, Exelon is reportingBGE 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 havebeen 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 directlycharged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot bedirectly 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 theconsolidated 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 ownsmore 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’spreferred securities, which PECO redeemed in 2013. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million atDecember 31, 2014 and December 31, 2013, as equity, PECO’s preferred securities as preferred securities of subsidiary through their redemptionin 2013, and BGE’s preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGEis subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly byRF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interestin 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. Theremaining interests are included in noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2—VariableInterest Entities for further discussion of Exelon’s and Generation’s VIEs and the reversionary interests of the noncontrolling members for thesecertain subsidiaries. ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC, of whichComEd owns 75% and an additional12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2014 and December 31, 2013, as equity. 243Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 intercompanytransactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over theoperations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of aVIE. Where Exelon does not have a controlling financial interest in an entity, it applies proportional consolidation, equity method accounting or costmethod accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for itsshare of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electricplants and transmission facilities, as well as its undivided ownership interests in Upstream natural gas exploration and production activities. Underproportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to theundivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership incommon stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments andjoint ventures, including certain financing trusts of ComEd, PECO, and BGE. Under the equity method, Exelon reports its interest in the entity asan investment and Exelon’s percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the costmethod if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizesincome 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 inaccordance 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 andassumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates havebeen made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirementbenefits, 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 andunbilled 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 BalanceSheets and Consolidated Statements of Cash Flows have been reclassified between line items for comparative purposes. The reclassifications didnot 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 operationsthat meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost ofproviding services or products; and (3) there is a reasonable expectation 244Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 regulatedoperations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, thePAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under variousFederal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements ofOperations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recordedregulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue toevaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration ofcurrent events in their respective regulatory and political environments. If a separable portion of ComEd’s, PECO’s or BGE’s business was nolonger able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statementsthe 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. The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financialstatements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts onthe parties affected by the order. 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 eachmonth, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records its bestestimates of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval bythe ICC and FERC in accordance with its formula rate mechanisms. BGE records its best estimate of the transmission revenue impact resultingfrom 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 reportsales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations, theclassification of which depends on the net hourly activity. In addition, capacity revenue and expense classification is based on the net sale orpurchase 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 ofderivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification ofrevenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This willresult in the change in fair value recorded through revenue. As of the Constellation merger date, Exelon and Generation have currently elected tode-designate all of their commodity cash flow hedge positions. As ComEd receives full cost recovery for energy procurement and related costsfrom retail customers, ComEd records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatoryasset or liability on its Consolidated Balance Sheets. Refer to Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments forfurther information. 245Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 authoritativeguidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs relatedto energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes areaccounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note 12—DerivativeFinancial 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 ofassets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred on the Registrants’ Consolidated BalanceSheets and are recognized in book income over the life of the related property. In accordance with applicable authoritative guidance, theRegistrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-notrecognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likelyof 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 technicalmerits, 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 havemet the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense or Other incomeand 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 forFederal 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 othertaxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes areimposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on thecustomer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and ComprehensiveIncome. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reportedon 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. 246Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, 2014and 2013, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, visionand long-term disability benefits. Additionally, as of December 31, 2014 and 2013, Generation’s restricted cash and cash equivalents primarilyincluded cash at Antelope Valley required for debt service and construction and cash at Continental Wind and ExGen Texas Power, which isrequired for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2014 and 2013, ComEd’srestricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As ofDecember 31, 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgageindenture. As of December 31, 2014 and 2013, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interestentity 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, 2014and 2013, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified asnoncurrent assets. As of December 31, 2014, Exelon, Generation, ComEd, PECO and BGE had investments in Rabbi trusts classified asnoncurrent 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. ForGeneration, the allowance is based on accounts receivable aging, historical experience and other currently available information. ComEd andPECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each companyto the outstanding receivable balance by customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accountson customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progressionwhich determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance foruncollectible accounts, which was consistent with ComEd and PECO, as described above. For additional information regarding the change inestimate, refer to Note 6—Accounts Receivable. Risk segments represent a group of customers with similar credit quality indicators that arecomputed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivablebalances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. ComEd, PECO and BGEcustomers’ accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normallyoccurs 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 economicconditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3—Regulatory Matters for additional informationregarding the regulatory recovery of uncollectible accounts receivable at ComEd. 247Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 specificrequirements: • requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to directmatters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefitsof 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 beused to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do nothave 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 ofthe consolidated VIE, and the liabilities of Exelon’s consolidated VIEs for which creditors do not have recourse to Exelon’s generalcredit. • Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantlyimpact 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 andgenerating plant materials. Materials are generally charged to inventory when purchased and expensed or capitalized to property, plant andequipment, as appropriate, when installed or used. Emission Allowances. Emission allowances are included in inventory (for emission allowances exercisable in the current year) and otherdeferred debits (for emission allowances that are exercisable beyond one year) and are carried at the lower of weighted average cost or market andcharged to fuel expense as they are used in operations. 248Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 investmentsand 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 inregulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables fromaffiliates 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 certainGeneration Rabbi trust investments and BGE’s Rabbi trust investments are included in earnings at Exelon, Generation and BGE. Unrealized gainsand 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 ofComEd’s and PECO’s available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If thedecline 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 costbasis and the amount of the write-down is included in earnings. See Note 15—Asset Retirement Obligations for information regarding marketablesecurities held by NDT funds and Note 23—Supplemental Financial Information for additional information regarding ComEd’s and PECO’sregulatory 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 constructionactivities. When appropriate, original cost also includes capitalized interest for Generation and Exelon Corporate and AFUDC for regulated propertyat ComEd, PECO and BGE. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements ofproperty, 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 ofconstruction costs (CIAC) are recorded as a reduction to Property, Plant and Equipment. DOE SGIG funds reimbursed to PECO and BGE areaccounted for as CIAC. For Generation, upon retirement, the cost of property is charged to accumulated depreciation in accordance with the composite method ofdepreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part ofthe cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurredfor 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 accordancewith the composite method of depreciation. ComEd’s and BGE’s depreciation expense includes the estimated cost of dismantling and removingplant from service upon retirement, which is consistent with each utility’s regulatory recovery method. ComEd’s and BGE’s actual incurred removalcosts are applied against a related regulatory liability. PECO’s removal costs are capitalized to accumulated depreciation when incurred, andrecorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. 249Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 forthese activities under the successful efforts method of accounting. Acquisition, development and exploration costs are capitalized. Costs ofdrilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commerciallyviable. 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 additionalinformation 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 expensedthrough 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 theDOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. On-siteSNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. SeeNote 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 expenseor 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 arecapitalized when management considers project completion to be probable, primarily based on management’s determination that the project iseconomically and operationally feasible, management and/or the Exelon board of directors has approved the project and has committed to a planto develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of requiredregulatory approvals is probable. Capitalized development costs are charged to Operating and maintenance expense when project completion is nolonger probable. At December 31, 2014 and 2013, there were not material capitalized development costs for projects not yet under constructionincluded in Property, plant and equipment, net on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $13 million, $10 millionand $4 million of costs were expensed by Exelon and Generation for the years ended December 31, 2014, 2013, and 2012, respectively. Thesecosts primarily related to the possible development of new renewable energy projects. 250Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 useare capitalized. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generallynot to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant toprescribed regulatory requirements. The following table presents net unamortized capitalized software costs and amortization of capitalizedsoftware costs by year: Net unamortized software costs Exelon Generation 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 Generation ComEd PECO BGE 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 ofoperations 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 yearended 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 andequipment on a straight-line basis using the composite method. ComEd’s and BGE’s depreciation includes a provision for estimated removal costsas authorized by the respective regulators. The estimated service lives for ComEd, PECO and BGE are primarily based on the average servicelives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities arebased on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent thatsuch renewal has not yet been granted) for all of Generation’s operating nuclear generating stations except for Oyster Creek. The estimatedservice lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewalextension of the operating licenses. The estimated service lives of the fossil fuel and other renewable generating facilities are based on theremaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments taking into account economic andcapital 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 theestimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level fordevelopment 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 orregulatory agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred costor income would 251 (a) (a) (a)(b) (a)(b) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 incometax-related regulatory assets, generally, when the recovery period is more than one year, the amortization is recorded to Depreciation andamortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s distribution formularate regulatory asset and ComEd’s and BGE’s transmission formula rate regulatory assets is recorded to Operating revenues. Amortization ofincome tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets andliabilities discussed above, when the recovery period is more than one year, the amortization is recorded to Depreciation and amortization in theRegistrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 3—Regulatory Matters and Note 23—Supplemental Financial Information for additional information regarding Generation’s nuclearfuel, 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 retirementactivity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligationrelated 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, costescalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unlesscircumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors andprobabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclearunits at least every five years. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing rotational basis, at least onceevery five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing oramount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted throughout each year to reflect thetime value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statementsof Operations and Comprehensive Income or, in the case of the majority of ComEd’s, PECO’s, and BGE’s accretion, through an increase toregulatory 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 isthe cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC isrecorded to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and otherincome and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatoryauthorities. 252Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Generation ComEd PECO BGE 2014 Total incurred interest $1,144 $419 $323 $115 $118 Capitalized interest 63 63 — — — Credits to AFUDC debt and equity 37 — 5 8 24 2013 Total incurred interest $1,423 $411 $584 $117 $129 Capitalized interest 54 54 — — — Credits to AFUDC debt and equity 35 — 16 6 13 2012 Total incurred interest $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 ofoperations 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 yearended 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.(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 inissuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events orconditions occur. The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under theguarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration orsettlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 22—Commitments andContingencies 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, whencircumstances indicate the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating businessclimate, including, but not limited to, current energy prices and market conditions, condition of the asset, specific regulatory disallowance, or plansto dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups areimpaired by comparing their undiscounted expected future cash flows to their carrying value. When the undiscounted cash flow analysis indicatesa long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carryingamount 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 independentof the cash flows of other assets and liabilities. The cash flows from the generating units are generally evaluated at a regional portfolio level alongwith cash flows generated from the customer supply and risk management activities, including cash flows 253 (a)(b) (a)(b) (b) (c) (c) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, generationassets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations areindependent 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 liabilitiesassumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if anevent occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note10—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 theyare 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 theirproportionate 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 plantsin Georgia. Exelon reviews the estimated residual values of its direct financing lease investments and records an impairment charge if the reviewindicates 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 normalpurchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as eitherhedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecastedtransaction 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 inaccumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of anyhedge are recognized in earnings immediately. For derivative contracts intended to serve as economic hedges and that are not designated or donot qualify for hedge accounting or the normal purchases and normal sales exception, changes in the fair value of the derivatives are recognized inearnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on theConsolidated Statement of Operations based on the activity the transaction is economically hedging. For energy-related derivatives entered into forproprietary trading purposes, which are subject to Exelon’s Risk Management Policy, changes in the fair value of the derivatives are recognized inearnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statement ofOperations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cashflows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. 254Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 remainedprobable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and was reclassified to results ofoperations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivatives executed tohedge economic risk related to commodities are recorded at fair value with changes in fair value recognized through earnings for the combinedcompany. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of itscustomers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energymarkets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales arecontracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable periodof time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchasesand normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financialinstruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 12—DerivativeFinancial 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, BGEand 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 numerousassumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. Theimpact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognizedover time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projectedbenefit 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, inequity in earnings (losses) of unconsolidated affiliates. Equity in earnings (losses) of unconsolidated affiliates also includes any adjustments toamortize the difference, if any, except for goodwill and land, between their cost in an equity method investment and the underlying equity in netassets 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 investmentsand which could result in the recognition of an impairment loss if such investment experiences an other than temporary decline in value. 255Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 believesmay significantly affect the Registrants. Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit CarryforwardsExist In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred taxassets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. This guidance waseffective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The adoption of thisstandard 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 theacquirer’s basis of accounting for the acquired entity’s assets and liabilities) when an acquirer obtains control of them. At the same time, the SECrescinded its guidance on pushdown accounting. The SEC’s guidance had required pushdown accounting in certain circumstances, made itoptional in others and prevented it in still other circumstances. The new guidance is effective immediately for any future transaction or to the mostrecent event in which an acquirer obtains or obtained control of the acquired entity. The adoption of the guidance had no impact to the financialstatements 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. Thenew guidance replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizingand measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenuerecognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. Theunderlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entityexpects 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 periodwithin annual reporting periods beginning on or after December 15, 2016. Early adoption is not permitted. The guidance can be appliedretrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retainedearnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currentlyassessing the impacts this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as thetransition method that they will use to adopt the guidance. 256Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 amountof 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 votingrights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the rightto receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is theenterprise 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, forwhich the applicable Registrant was the primary beneficiary. As of December 31, 2014 and 2013, the Registrants had significant interests in sixand eight other VIEs, respectively, for which the Registrants do not have the power to direct the entities’ activities and, accordingly, were not theprimary beneficiary. Consolidated Variable Interest Entities The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financialstatements at December 31, 2014 and 2013 are as follows: December 31, 2014 December 31, 2013 Exelon Generation BGE Exelon 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 foradditional information. Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in thetable 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, toacquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCopurchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization chargespayable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchasecosts 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 (a)(b) (b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 itreceives from customers for rate stabilization charges to BondCo. During 2014, 2013, and 2012, BGE remitted $85 million, $83 million, and $85million, respectively, to BondCo. BGE did not provide any additional financial support to BondCo during 2014. Further, BGE does not have any contractual commitments orobligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do nothave any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interestpayments of BondCo. Retail Gas Group. During 2009, Constellation formed two new entities, which now are part of Generation, and combined them with itsexisting retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third-partygas supplier. While Generation owns 100% of these entities, it has been determined that the retail gas entity group is a VIE because there is notsufficient equity to fund the group’s activities without the additional credit support that is provided in the form of a parental guarantee. Generation isthe 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 canmake 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 toprovide additional financial support under the collateralized third-party gas supply agreement. The third-party gas supply creditors do not have anyrecourse 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 operatesolar power facilities, which are now part of Generation. Additionally, on September 30, 2011, Generation acquired all of the equity interests inAntelope Valley Solar Ranch One (Antelope Valley) from First Solar, Inc., a 242-MW solar PV project under construction in northern Los AngelesCounty, California. While Generation owns 100% of these entities, it has been determined that certain of the individual solar project entities areVIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers inorder to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through thefixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the solar project entities that qualify as VIEs becauseGeneration controls the design, construction, and operation of the solar power facilities. Generation provides operating and capital funding to thesolar entities for ongoing construction, operations and maintenance of the solar power facilities and provides limited recourse related to theAntelope Valley project. In addition, these solar VIE entities have an aggregate amount of outstanding debt with third parties of $642 million, as ofDecember 31, 2014, for which the creditors have no 258Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theAntelope 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 beneficiaryas a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economicperformance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $5 million in creditsupport for the retail power companies. These entities are included in Generation’s consolidated financial statements, and the consolidation of theVIEs 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 wereacquired 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 variabilityfrom 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, andoperation of the wind generation facilities. While Generation owns 100% of the majority of the wind project entities, nine of the projects havenoncontrolling equity interests of 1% held by third parties. Generation’s current economic interests in eight of these projects is significantly greaterthan its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interestholder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects tothe noncontrolling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements withthe noncontrolling interests state that Generation is to provide financial support to the projects in proportion to its current 99% economic interestsin the projects. However, no additional support to these projects beyond what was contractually required has been provided during 2014. As ofDecember 31, 2014, the carrying amount of the assets and liabilities that are consolidated as a result of Generation being the primary beneficiaryof 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 aboard of ten directors, five of which were appointed by Generation and five by EDF. CENG was designed to operate under joint and equal control ofGeneration and EDFI through the Board of Directors, subject to the Chairman of the Board’s final decision making authority on certain specialmatters; therefore, CENG was not subject to VIE guidance. Accordingly, Generation’s 50.01% interest in CENG was accounted for as an equitymethod 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 andadministrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generationnuclear fleet, subject to the CENG member rights of EDFI. As a result of executing the NOSA, CENG now qualifies as a VIE due to thedisproportionate relationship between Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENGand 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, 259Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Generationderecognized Generation’s equity method investment in CENG and reflected all assets, liabilities, and the EDFI noncontrolling interest in CENG atfair value on the consolidated balance sheets of Exelon and Generation, resulting in the recognition of a $261 million gain in their respectiveConsolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. For additional information on thistransaction 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 CENGsubsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of theCENG 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 theCENG 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 plantsthrough 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-partyclaims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclearplants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 22—Commitmentsand Contingencies for more details), • in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million ofthe 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 premiumadjustments 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 undergroundstorage tanks. In addition, EDFI executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of anyamounts 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 theinsurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportionto their respective member interests (see Note 22—Commitments and Contingencies for more details), and 260Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 guaranteeof 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. 261Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 beused 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 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 Note16—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 salecontracts. For the equity investments, the carrying amount 262(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 energypurchase and sale contracts and the fuel purchase commitments (commercial agreements), the carrying amount of assets and liabilities inExelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capitalaccounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billingcycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangementsor 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 andcertain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of Generation’s ownership interest in fourunconsolidated VIEs in 2014, offset by the execution of an energy purchase and sale agreement with an unconsolidated VIE and an equityinvestment in another unconsolidated VIE. The following tables present summary information about Exelon and Generation’s significantunconsolidated VIE entities: December 31, 2014 CommercialAgreementVIEs EquityInvestmentVIEs Total Total assets $506 $91 $597 Total liabilities 237 49 286 Exelon’s ownership interest in VIE — 9 9 Other ownership interests in VIE 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 27 — 27 December 31, 2013 CommercialAgreementVIEs EquityInvestmentVIEs Total Total assets $128 $332 $460 Total liabilities 17 123 140 Exelon’s ownership interest in VIE — 86 86 Other ownership interests in VIE 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 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 provideinformation 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 pledgedfor Zion Station decommissioning includes gross pledged assets of $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset bypayables 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 informationregarding the relative size of the ZionSolutions LLC unconsolidated VIE. 263 (a) (a) (a) (a) (b) (a) (a) (a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(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, thereare no agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in thesevariable 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 areVIEs because the entity absorbs risk through the sale of fixed price power and renewable energy credits. Generation has reviewed the entities andhas determined that Generation is not the primary beneficiary of the VIEs because Generation does not have the power to direct the activities thatmost 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 acounterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in orderto monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sold power to the VIEswhich, in turn, sold that power to an electric distribution utility through 2013. In connection with this transaction, a third-party acquired the equity ofthe VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation tobuy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generationwould have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidationwas not required. During 2013, the third-party repaid their obligations of the loan with Generation which caused the entities to no longer beunconsolidated 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 assetsand liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through theput option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation isnot required. Other than the asset sale agreement, Exelon and Generation do not have any contractual or other obligations to provide additionalfinancial 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 obtainedthrough its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies fornuclear and fossil generation. These contracts and Generation’s membership in NEIL are discussed in further detail in Note 22—Commitments andContingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in anentity 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 consideredsignificant because of the small proportion of the entities’ activities encompassed by the contracts with Generation. Further, Generation hasconsidered which 264Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(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 theprimary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right toreceive 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 fabricationprocess. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operationalrisk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financialsupport through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22—Commitmentsand Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entitiesor 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 energydevelopment projects and energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks ofeach of its equity investments, and determined that certain of the entities are VIEs because the entity has an insufficient amount of equity at riskto 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 becauseGeneration 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 financingtrust of BGE, BGE Capital Trust II are not consolidated in Exelon’s, ComEd’s, PECO’s or BGE’s financial statements. These financing trusts werecreated to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significantvariable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest inthe financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13—Debt and Credit Agreements foradditional 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 astructure for substantial capital investment by utilities to modernize Illinois’ electric utility infrastructure. Participating utilities are required to file anannual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in 265Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(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. Theupdate 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 revenuesfor any differences between the revenue requirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approvedby the ICC for that year’s reconciliation. As of December 31, 2014, and December 31, 2013, ComEd had a regulatory asset associated with thedistribution formula rate of $371 million and $463 million, respectively. The regulatory asset associated with distribution true-up is amortized toOperating 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 $269million. 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 wasset 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 metricspenalty of 5 basis points for the 2013 reconciliation). The rates took effect in January 2015. ComEd and intervenors requested a rehearing onspecific 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 totalincrease to the revenue requirement of $353 million. On December 19, 2013, the ICC issued its final order which increased the revenuerequirement by $341 million, reflecting an increase of $160 million for the initial revenue requirement for 2013 and an increase of $181 million forthe annual reconciliation for 2012. The final revenue requirement reflected the impacts of Senate Bill 9, which became effective in May 2013 andclarified 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 andcapital structure in the annual reconciliation; and the use of ComEd’s weighted average cost of capital interest rate rather than a short-term debtrate 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 oncommon 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, whichincreased the revenue requirement by $73 million, reflecting an increase of $80 million for the initial revenue requirement for 2012 and a decreaseof $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 allowedreturn 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 theICC’s decision on the issues on appeal. On May 30, 2013, ComEd updated its revenue requirement allowed in the December 2012 Order to reflectthe 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 July2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appealswith the Illinois Appellate Court. The Illinois Appellate Court reaffirmed the ICC’s order. 266Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, tochange the formula rate structure by requesting three changes: the elimination of the income tax gross-up on the weighted average cost of capitalused to calculate interest on the annual reconciliation balance, the netting of associated accumulated deferred income taxes against the annualreconciliation balance in calculating interest, and the use of average rather than year-end rate base for determining any ROE collar adjustment. OnNovember 26, 2013, the ICC issued its final order in the Investigation, rejecting two of the proposed changes but accepting the proposed change toeliminate the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance. Theaccepted change became effective in January 2014, and reduced ComEd’s 2014 revenue by approximately $8 million. This change had nofinancial statement impact on ComEd in 2013. ComEd and intervenors requested rehearing, however all rehearing requests were denied by theICC. 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’sinitial formula rate tariff. The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislationand were clarified by subsequent legislation (Senate Bill 9). Therefore, only a subset of the issues originally appealed remained. The Court foundagainst ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. TheCourt’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 jurisdictionalcosts. On July 2, 2014, the ICC filed its Answer to the Petition, arguing that Supreme Court review is not necessary or appropriate. Under theprocedural 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 onthe 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 newScience and Technology Innovation Trust fund on July 31, 2012, and will make recurring annual contributions of $4 million, the first of which wasmade 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 utilityinfrastructure. Participating utilities are required to file an annual update on their AMI implementation progress. In March 2014, ComEd filed apetition with the ICC for approval to accelerate the deployment of AMI meters. On June 11, 2014, the ICC approved ComEd’s 267Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Chicagoarea. Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd’s 2007 electricdistribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, whichbecame effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other partiesfiled appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEdon 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 accumulateddepreciation while including post-test year pro forma plant additions through that period. ComEd continued to bill rates as established under theICC’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 subsequentICC proceedings, the ICC issued an order requiring ComEd to provide a refund of approximately $37 million to customers related to the treatmentof 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 ofapproximately $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 ComEdcustomers were eligible for a refund. ComEd was fully reserved for this liability at December 31, 2013. As of December 31, 2014 ComEd hadrefunded substantially all amounts to customers. Advanced Metering Program Proceeding (Exelon and ComEd). As part of ComEd’s 2007 Rate Case, the ICC approved recovery ofcosts associated with ComEd’s Rider SMP for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approvedComEd’s AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had nocollections under Rider SMP through December 31, 2014. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer ofcertain 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 Courtreversed 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 forLeave 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 appropriaterefund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, whichwere submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount theyclaim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC’s approval of the costrecovery provisions of Rider SMP. During the second quarter of 2014, ComEd reached a tentative agreement to jointly resolve the disputed refundclaim. On September 18, 2014, the ICC approved a refund of $9.5 million 268Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 toconstruct 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 constructionwork in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyondComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costsincurred prior to May 21, 2014 in ComEd’s transmission rate base. On October 22, 2014, the ICC issued an order approving ComEd’s GrandPrairie Gateway Project over the objection of numerous landowners and the City of Elgin. Four parties filed timely applications for rehearing beforethe ICC. On November 25, 2014, the ICC denied the rehearing application filed by the Forest Preserve District of Kane County, but grantedrehearing on the application of certain landowners who requested that the ICC consider an alternate route for a three-mile segment of the line inKane 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 SKPlandowner group and Utility Risk Management Corporation (collectively, the SKP/URMC party), each filed a Notice of Appeal with the SecondDistrict Appellate Court. On February 3, 2015, the ICC filed motions with the Second District Appellate Court seeking to extend the time for theICC 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. ComEdexpects 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 thoseamounts on ComEd’s bill to customers. Receivables are purchased at a discount to compensate ComEd for uncollectible accounts. ComEdproduces consolidated bills for the aforementioned retail customers reflecting charges for electric delivery service and purchased receivables. Asof December 31, 2014, the balance of purchased accounts receivable was $139 million. ComEd recovers from RES and customers the costs forimplementing and operating the program under an ICC approved tariff. A number of municipalities, including the City of Chicago have switched toRES 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 costsfrom retail customers without mark-up. Since June 2009, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and theIPA 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 energyresources. Purchases by customers of electricity from competitive generation suppliers, whether as a result of the customers’ own actions or as aresult of municipal aggregation, are not included in this calculation and have the effect of reducing ComEd’s purchase obligation. 269Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 renewableenergy 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 procurementsduring 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 onComEd’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 anexisting plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operationdate in 2017. The sourcing agreement provides that ComEd and Ameren will pay FutureGen’s contract prices, which are set annually pursuant to aformula rate. The contract prices are based on the difference between the costs of the facility and the revenues FutureGen receives from sellingcapacity and energy from the unit into the MISO or other markets, as well as any other revenue FutureGen receives from the operation of thefacility. 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 forretail customers purchasing electricity from competitive electric generation suppliers. On July 22, 2014, the Illinois Appellate Court issued its rulingre-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover itscosts. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electricgeneration suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, theIllinois 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 andReinvestment Act of 2009. In early February 2015, the DOE suspended funding for the project until further clarity could be obtained on certainsignificant hurdles facing the project, including the outcome of the litigation described above. Whether or not the DOE funding will be reinstated atsome 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 ICCseeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distributioncustomers, which was approved by the ICC on September 30, 2014. Depending on eventual market conditions and the cost of the facility, thesourcing 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. 270Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 deliveredto retail customers for the year ended June 1, 2009, which increases annually to 2.0% of energy delivered in the year commencing June 1, 2015and each year thereafter. Additionally, during the ten-year period that began June 1, 2008, electric utilities must implement cost-effective demandresponse measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand responsegoals 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 Plancovering the period June 2014 through May 2017. The plans are designed to meet Illinois’ energy efficiency and demand response goals throughMay 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 annuallythereafter, as part of the IPA procurement plan, ComEd is to include cost-effective expansion of current energy efficiency programs, and additionalnew cost-effective and/or third-party energy efficiency programs that are identified through a request for proposal process. All cost-effective energyefficiency programs are included in the IPA procurement plan for consideration of implementation. While these programs are monitored separatelyfrom the Energy Efficiency Portfolio Standard (EEPS), funds for both the EEPS portfolio and IPA energy efficiency programs are collected underthe same rider. Illinois utilities are required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricitythat each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that willcumulatively 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 aresubject to rate impact criteria set forth by Illinois legislation. As of December 31, 2014, ComEd had purchased sufficient renewable energyresources 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 andContingencies 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 approvedthe settlement of PECO’s electric and natural gas distribution rate cases, which were filed in March 2010, providing increases in annual servicerevenue of $225 million and $20 million, respectively. The electric settlement provides for recovery of PJM transmission service costs on a fulland 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 repairsdeduction methodology are to be handled from a rate-making perspective. The settlements require that the expected cash benefit from theapplication of any new guidance to tax years prior to 2011 be refunded to customers over a seven-year period. On August 19, 2011, the IRSissued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECOadopted the safe harbor and 271Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 safeharbor to costs incurred prior to 2010 is $171 million. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to execute therefund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return, whichis 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 taxyear. 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 $54million. This amount is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills sinceJanuary 1, 2013. PECO currently anticipates that the IRS will issue guidance during 2015 providing a safe harbor method of accounting for gastransmission 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 areclaimed on the tax return and will be reflected in the determination of revenue requirements in the next electric and natural gas distribution ratecases. 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 arebased, 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 wasproviding default electric service, had a 29-month term that ended May 31, 2013. On October 12, 2012, the PAPUC issued its Opinion and Orderapproving 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 ispermitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides forthe recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or undercollections. In addition, PECO’s second DSP Program provides for the recovery of AEPS compliance costs through the GSA rather than aseparate AEPS rider. In the second DSP Program, PECO procured electric supply for its default electric customers through five competitive procurements. Theload for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contractsof two years or less. For the large commercial and industrial class load, PECO has competitively procured contracts for full requirements defaultelectric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. PECOentered into contracts with PAPUC approved bidders, including Generation, for its five competitive procurements. Charges incurred for electricsupply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Statement of Operations andComprehensive Income. In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previouslyissued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan to allow its low-income Customer AssistanceProgram (CAP) customers to purchase their generation supply from EGSs beginning in April 2014. On May 1, 2013, 272Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) PECO filed its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, withmodifications, 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 Courtissued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court’s review, PECO will not implement CAPShopping. 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 throughMay 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. On August 28, 2014, PECO filed a Joint Petitionfor Partial Settlement, which affirmed PECO’s procurement plan for Residential and Small Commercial customers. On December 4, 2014, thePAPUC approved PECO’s third DSP Program, as modified by the Joint Petition for Partial Settlement, without modification or limitation. Separatefrom the Joint Petition for Partial Settlement, the PAPUC also approved other items related to the program. The plan outlines how PECO willpurchase electric supply for default service customers. PECO will procure electric supply through four competitive procurements for fixed price fullrequirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price fullrequirement 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, inApril 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than1.6 million electric smart meters and an AMI communication network by 2020. The first phase of PECO’s SMPIP, which was completed onJune 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with thatnetwork. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUCwhich was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO’s universaldeployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO’sSMPIP, 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 thesecond quarter of 2015. In total, PECO currently expects to spend up to $583 million, excluding the cost of the original meters (as furtherdescribed 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 smartmeter 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 theagreement, the DOE has a conditional ownership interest in qualifying Federally-funded project property and equipment, which is subordinate toPECO’s existing mortgage. The SGIG funds were used by PECO to offset the total impact to ratepayers of the smart meter deployment requiredby Act 129. As of the third quarter of 2014, PECO received all of the $200 million, including $4 million for sub-recipients, in reimbursements. OnOctober 15, 2014, the DOE issued a Close Out of Post-Award Project Cost Verification Audit, in which it was determined that PECO fully met itsrequired cost share, and the audit was closed with no further action required. 273Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 involvingoverheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed afterSeptember 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previouslyinstalled meters with an alternative vendor’s meters. PECO is moving forward with the alternative meters during universal deployment andcontinues 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 beused, the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the currentperiod’s earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, ownedby PECO was approximately $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million ofdepreciation. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any agreementwith 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 PECOtransferred the original uninstalled meters to the vendor and will receive $12 million in return. On January 23, 2014, PECO entered a finalagreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation andremoval costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously hadintended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed suchcosts were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatoryasset was established at the time of the removals. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory assetbalance as a receivable, which has been fully collected, with no gain or loss impacts on future results of operations. On March 14, 2014, PECOfiled its quarterly smart meter recovery surcharge with the PAPUC which included PECO’s proposed treatment of the final agreement with thevendor. 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 onJune 1, 2009 and concluded on May 31, 2013. The Phase I plan set forth how PECO would meet the required reduction targets established by Act129’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 annualsystem 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 preliminaryfiling 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 costsnecessary to implement the Phase I Plan. The Petition sought approval to allow PECO to recover $12 million in equipment, installation andinformation technology costs for its Residential DLC program with the amounts collected for the Phase I Plan. As the Phase I Plan wasimplemented at a cost less than originally budgeted, PECO proposed to recover these expenses from its Phase I Energy Efficiency ProgramCharge over- 274Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 onMay 9, 2013. A regulatory liability was established for the DLC program costs that will be amortized as a credit to the income statement to offsetthe 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 requirementsfor 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-yearcumulative 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. Theplan 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 throughMay 31, 2016, adjusted for weather and extraordinary loads. The implementation order permits PECO to apply any excess savings achievedduring Phase I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 PhaseII implementation order, at least 10% and 4.5% of the total consumption reductions must be through programs directed toward PECO’s public andlow income sectors, respectively. If PECO fails to achieve the required reductions in consumption, it will be subject to civil penalties of up to $20million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of the plan may not exceed 2% of the electriccompany’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 formass market customers from June 1, 2013 to May 31, 2014. PECO proposed to fund the estimated $10 million costs of the one-year program bymodifying incentive levels for other Phase II programs. On May 9, 2013, the PAPUC approved PECO’s amended EE&C Phase II plan. The costsof 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 proposeddemand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale pricessuppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it willprescribe additional demand response obligations until 2015. Any decision reached would affect PECO’s EE&C Plan subsequent to its Phase IIPlan. On February 28, 2014, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction programfor mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program bymodifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy EfficiencyProgram Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO’s Petition. The Orderbecame final on May 5, 2014. Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Actmandated that beginning in 2011, following the expiration of PECO’s rate cap transition period, certain percentages of electric energy sold toPennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement forelectric energy that must come from Tier I alternative energy resources ranges 275Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 compliancepercentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. These Tier I andTier 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 8,000solar Tier I AECs annually in accordance with a PAPUC approved plan. The plan allowed PECO to bank AECs procured prior to 2011 and use thebanked AECs to meet its AEPS Act obligations over two compliance years ending May 2013. The PAPUC also approved the procurement of TierII 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 asurcharge. PECO’s second DSP Program eliminated the AEPS surcharge. Beginning in June 2013, AEPS compliance costs are being recoveredthrough the GSA. Pennsylvania Retail Electricity and Gas Markets (Exelon and PECO). Beginning in 2011, the PAPUC issued an order outlining the nextsteps in its investigation into the status of competition in Pennsylvania’s retail electricity market. The PAPUC found that the existing defaultservice model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office ofCompetitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. Through variousorders, the PAPUC issued default electric service pricing for customers in PECO’s service territory. See Pennsylvania procurement proceedingsdiscussed above for additional details. In early 2014, the extreme weather in PECO’s service territory resulted in increased electricity commodity costs causing certain shoppingcustomers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, onApril 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electricgeneration suppliers to provide more consumer education regarding their contract. The second rulemaking order requires electric distributioncompanies to enable customers to switch suppliers within three business days (known as accelerated switching). The improved customereducation and accelerated switching were to be in place within 30 days and six months of approval of the orders, respectively. The orders becamefinal on June 14, 2014. On December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on Supplier Switch), allowingPECO 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, includingthe role of the existing default service model and opportunities for market enhancements. On December 18, 2014, the PAPUC issued a Final Orderdirecting the Office of Competitive Market Oversight to continue its investigation, confirming that natural gas distribution companies should remainwith the default service model for the time being and directing establishment of a working group to examine other competitive issues. Commentson the Final Order were due on February 2, 2015. PECO will continue to monitor the Order and assess compliance, as necessary. 276Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 toclarify the PAPUC’s authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution systemimprovement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric andnatural gas distribution systems in Pennsylvania. Act 11 also includes a provision that allows utilities to use a fully projected future test year underwhich the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service during the first yearrates are in effect. On August 2, 2012, the PAPUC issued a Final Order establishing rules and procedures to implement the ratemaking provisionsof Act 11. The implementation order requires a utility to have a long-term infrastructure improvement plan (LTIIP) which outlines how the utility isplanning to increase its investment for repairing, improving, or replacing aging infrastructure, approved by the Commission prior to implementing aDSIC. 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 thereplacement of existing gas mains and also included a plan for the relocation of meters from indoors to outside in accordance with a recentPAPUC 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 tothe 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. TheSettlement Agreement establishes new depreciation rates which have the effect of decreasing annual depreciation expense by approximately $20million, primarily for electric. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreementwithout modification, which became a final order on December 12, 2014. The approved distribution rate order authorizing BGE to increase electricand 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, BGEfiled for electric and gas base increases with the MDPSC, ultimately requesting increases of $83 million and $24 million, respectively. In additionto these requested rate increases, BGE’s application includes a request for recovery of incremental capital expenditures and operating costsassociated with BGE’s proposed short-term reliability improvement plan (the “ERI initiative”) in response to a MDPSC order through a surchargeseparate 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 annualdistribution service revenue of $34 million and $12 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. Ratesbecame effective for services rendered on or after December 13, 2013. The MDPSC also authorized BGE to recover through a surchargemechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the conditionthat the MDPSC approve specific projects in advance of cost recovery. On March 31, 2014, after reviewing comments filed by the parties andconducting a hearing on the matter, the MDPSC approved all but one project proposed 277Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 asurcharge update including a true-up of cost estimates included in the 2014 surcharge, along with its work plan and cost estimates for 2015, to beincluded in the 2015 surcharge. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2014 annual report, 2015work 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 inBGE’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 hearingwas 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 toits electric and gas base rates with the MDPSC. On February 22, 2013, the MDPSC issued an order for increases in annual distribution servicerevenue of $81 million and $32 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. The rates becameeffective for services rendered on or after February 23, 2013. As part of the rate order, the MDPSC approved both recovery of and return on themerger integration costs, including severance, incurred during the test year for the Exelon and Constellation merger. As a result, the order affirmedthe treatment of $20 million of severance-related costs that BGE had recorded as a regulatory asset in 2012, consistent with prior MDPSCdecisions. Additionally, BGE established a new regulatory asset of $8 million related to non-severance merger integration costs, which includes $6million of costs incurred during 2012. Current MDPSC treatment of these merger integration regulatory assets is to provide recovery over a fiveyear period. 2011 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). In March 2011, the MDPSC issued a comprehensive rateorder setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As partof the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs are beingrecovered over a 5-year period that began in December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. Theregulatory 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 initiativefor 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 associatedincremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advancedmetering system is implemented. As of December 31, 2014 and December 31, 2013, BGE recorded a regulatory asset of $128 million and $66million, 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 beamortized 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 customerselecting to opt-out of BGE’s smart meter installation program, 278Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 authorizedby the order will be reviewed after an initial 12 to 18 month period. On November 25, 2014, the MDPSC issued a decision approving BGE’sproposal to automatically enroll unresponsive customers into the opt-out program and to charge those customers opt-out fees after BGE hasexhausted attempts to schedule a meter installation. The ultimate impact of opt-out could affect BGE’s ability to demonstrate cost-effectivenessof 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 todemonstrate 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 utilitiesto 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 ofthe proposed contract is 20 years. The CfD mandates that BGE and the other utilities pay (or receive) the difference between CPV’s contractprices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. The MDPSC’s order requires thethree 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 executedthe 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 andfinancial 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 thatchallenged the actions taken by the MDPSC on Federal law grounds. On October 24, 2013, the U.S. District Court issued a judgment order findingthat the MDPSC’s Order directing BGE and the two other Maryland utilities to enter into a CfD, which assures that CPV receives a guaranteedfixed price regardless of the price set by the federally regulated wholesale market, violates the Supremacy Clause of the United StatesConstitution. On November 22, 2013, the MDPSC and CPV appealed the District Court’s ruling to the United States Court of Appeals for the FourthCircuit. On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC orderunder state law. That petition was subsequently transferred to the Circuit Court for Baltimore City and consolidated with similar appeals that havebeen filed by other interested parties. On October 1, 2013, the Circuit Court Judge issued a Memorandum Opinion and Order finding the decisionsof the MDPSC were within its statutory authority under Maryland law. This decision is separate from the judgment in the federal litigation that theMDPSC Order is unconstitutional and the CfD is unenforceable under federal law. The federal judgment, if upheld, would prevent enforcement ofthe CfD even if the Circuit Court decision stands. On October 29, 2013, BGE and the two other Maryland utilities appealed the Circuit Court’s rulingto 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 costrecovery as of the effective date of the agreement, the CfD could have a material impact on Exelon and BGE’s results of operations, cash flowsand financial positions. 279Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 infuture auctions to the detriment of Exelon’s market driven position. In addition to this litigation, Exelon is working with other market participants toimplement 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 interruptingelectrical service to a significant portion of the State of Maryland, the MDPSC issued an order on February 27, 2013 requiring BGE and otherMaryland utilities to file several comprehensive reports with short-term and long-term plans to improve reliability and grid resiliency that were due atvarious times before August 30, 2013. On September 3, 2013, BGE filed a comprehensive long term assessment examining potential alternatives for improving the resiliency of theelectric grid and a staffing analysis reviewing historical staffing levels as well as forecasting staffing levels necessary under various stormscenarios. During the summer of 2014, an evaluation of the reports filed by BGE and other Maryland utilities was undertaken by consultants onbehalf of the MDPSC and MDPSC Staff. The MDPSC Staff also proposed standards for reliability during major events and estimated times ofrestoration as well as undertaking an evaluation of performance-based ratemaking principles and methodologies that would more directly andtransparently align reliable service with the utilities’ distribution rates and that reduce returns or otherwise penalize sub-standard performance. TheMDPSC held hearings in September 2014. BGE currently cannot predict the outcome of these proceedings, which may result in increased capitalexpenditures and operating costs. The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the MarylandGeneral Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gascompanies 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 aproceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement projects along with a correspondingsurcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislationincludes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surchargerevenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding atwhich time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is requiredto file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associatedsurcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. OnMarch 26, 2014, the Maryland PSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surchargethat became effective April 1, 2014. On November 17, 2014, BGE filed a surcharge update including a true-up of costs estimates included in the2014 surcharge, along with its 2015 project list and cost estimates to be included in the 2015 surcharge. The filing was approved with a revisedsurcharge effective January 1, 2015. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2015 project list andthe 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 issuedby the MDPSC on BGE’s infrastructure replacement 280Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 andassociated surcharge. On October 10, 2014, the residential consumer advocate noticed its appeal to the Maryland Court of Special Appeals fromthe 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 theagreement, Ginna advised the New York Public Service Commission (NYPSC) and ISO-NY that in absence of a reliability need, Ginnamanagement would make a recommendation, subject to approval by the CENG board, that Ginna be retired as soon as practicable. A formal studyconducted by the ISO-NY and RG&E concluded that the Ginna nuclear plant needs to remain in operation to maintain the reliability of thetransmission 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). OnFebruary 13, 2015, regulatory filings, including RSSA terms negotiated between Ginna and RG&E, to support the continued operation of Ginna forreliability purposes were made with the NYPSC and with FERC for their approval. While the RSSA is expected to be approved, in absence of suchan agreement and in the event the plant was retired before the current license term ends in 2029, Exelon’s and Generation’s results of operationscould be adversely affected by increased depreciation rates, impairment charges, severance costs, and accelerated future decommissioningcosts, 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 resultingrates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capitaladditions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actualcosts incurred for that year. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases tooperating revenues for any differences between the revenue requirement in effect and ComEd’s and BGE’s best estimate of the revenuerequirement expected to be approved by the FERC for that year’s reconciliation. As of December 31, 2014, and 2013, ComEd had a regulatoryasset associated with the transmission formula rate of $21 million and $17 million, respectively, and BGE had a net regulatory asset associatedwith the transmission formula rate of $1 million and a net regulatory liability which was not material as of December 31, 2013. The regulatory assetassociated 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. Thefiling established the revenue requirement used to set rates that took effect in June 2014. ComEd’s 2014 281Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 allowedreturn on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. The time period for anychallenges 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 filingestablished the revenue requirement used to set rates that took effect in June 2013. ComEd’s 2013 formula transmission rate provides for aweighted average debt and equity return on transmission rate base of 8.70%, inclusive of an allowed return on common equity of 11.50%, adecrease from the 8.91% average debt and equity return previously authorized. The time period for any challenges to ComEd’s annual 2013formula 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 thecommon equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currentlycapped at 55%. In April 2014, BGE filed its 2014 formula rate update with the FERC reflecting an increased revenue requirement of $14 million, including anincrease of $9 million for the initial revenue requirement and an increase of $5 million related to the annual reconciliation. The annual updateestablished the revenue requirement used to set rates that took effect in June 2014. The time period for any challenges to BGE’s annual updateexpired 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%, anincrease from the 8.35% average debt and equity return previously authorized. As part of the FERC-approved settlement of BGE’s 2005transmission rate case in 2006, the rate of return on common equity for BGE’s electric transmission business for new transmission projects placedin 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 ofColumbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC againstBGE and the Pepco Holdings, Inc. companies relating to their respective transmission formula rates. BGE’s formula rate includes a 10.8% baserate of return on common equity (ROE) and a 50 basis point incentive for participating in PJM (the latter of which is conditioned upon crediting thefirst 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 formularate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, therevenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refundsrequired 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 judgeprocedures for the complaint, and set a refund effective date of February 27, 2013. BGE, the PHI companies and the parties began settlementdiscussions under the guidance of a FERC administrative law judge on September 23, 2014. On November 24, 2014, the 282Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 notpossible. On November 26, 2014, the Chief Judge issued an order terminating the settlement proceeding, designating a presiding judge at thehearings 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 regardingthe base ROE of the transmission business seeking a reduction from 10.8% to 8.8%. The filing of the second complaint creates a second refundwindow. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants’ requested refundeffective 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 arefund to customers of transmission revenue for the two maximum fifteen month periods will be required. However, BGE is unable to estimate themost likely refund amount for either complaint at this time, and has therefore established a reserve, which is not material, representing the low endof a reasonably possible estimated range of loss. Additionally, management is unable to estimate the maximum exposure of a potential refund atthis time, which may have a material impact on BGE’s results of operations and cash flows. The estimated annual ongoing reduction in revenues ifFERC approved the ROEs requested by the parties in their filings is approximately $11 million. If FERC were to order a reduction of BGE’s baseROE 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 equityfor certain new transmission investment), the result of the first fifteen month refund window would be a refund to customers of approximately $13million. 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 anyincentives that were credited to the base return on equity for certain new transmission investment) and the refund period extended for a full fifteenmonths, the result would be a refund to customers of approximately $14 million. PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE). PJM Transmission Rate Designspecifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE incur costs based on theexisting rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of newtransmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current ratedesign for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500kV 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 thecustomers 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 issuedits decision affirming FERC’s order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration itsdecision with regard to the costs of new facilities 500 kV and above. On March 30, 2012, FERC issued an order on remand affirming the costallocation in its April 2007 order. On March 22, 2013, FERC issued an order denying rehearing and made it clear that the cost allocation at issueconcerns only projects approved prior to February 1, 2013. A number of entities have filed appeals of the FERC orders. On June 25, 2014, theU.S. Court of Appeals for the Seventh Circuit issued a decision once again remanding to FERC the cost allocation of new facilities 500 kV andabove. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the issue of the costallocation for facilities 500 kV and above. The hearing only concerns new facilities approved 283Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofoperations, cash flows or financial position. PECO anticipates that all impacts of any rate design changes should be recoverable through thetransmission service charge rider approved in PECO’s 2010 electric distribution rate case settlement and, thus, the rate design changes are notexpected to have a material impact on PECO’s results of operations, cash flows or financial position. To the extent any rate design changes areretroactive to periods prior to January 1, 2011, there may be an impact on PECO’s results of operations. BGE anticipates that all impacts of anyrate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail ratesand, 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 maintainsystem 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) thatis intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The FERC orders approving theMOPR 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 tariffaimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts and capacity market speculators) cannotinappropriately 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 anopinion vacating the FERC Order No. 745 (“D.C. Circuit Decision”). Order No. 745 established uniform compensation levels for demand responseresources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets wererequired to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and wascost-effective. In addition to invalidating the compensation structure established by Order No. 745, the D.C. Circuit Court, in broad language, explained thatdemand response is part of the retail market and FERC is restricted from regulating retail markets. The full implication of the D.C. Circuit Decisionfor both energy and capacity markets regulated by FERC is not yet known and will depend on how FERC and the RTOs and ISOs implement thedecision. FERC and several other parties sought rehearing of the D.C. Circuit Decision, which was denied in September 2014. In addition, onSeptember 22, 2014, FERC and another party sought to stay the issuance of the D.C. Circuit Court’s mandate so that FERC may appeal thedecision 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 appealthe decision to the U.S. Supreme Court. 284Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 withthe 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 Tariffprovisions 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 andillegal to the extent that demand response resources cleared that auction. On November 14, 2014, the New England Power GeneratorsAssociation, Inc. (“NEPGA”) filed a similar complaint at FERC asking FERC to disqualify demand response from the upcoming capacity auction inNew England and to revise the New England tariff to remove demand response from participation in the capacity market. FERC’s response to theFirstEnergy complaint and the NEPGA complaint and its response to address the D.C. Circuit Court’s decision in all markets could precludedemand response resources from receiving any future capacity market revenues and also subject such resources to refund obligations. Inaddition, there is uncertainty as to how FERC might treat already settled capacity market auctions as well as future auctions, both for demandresponse resources and generation resources. FERC could grant all or a portion of the relief requested by FirstEnergy and may grant reliefretroactively or only prospectively. FERC could also pursue alternative means for allowing demand response to effectively participate in capacitymarkets it regulates. Due to these uncertainties, the Registrants are unable to predict the outcome of these proceedings, and the final outcome isnot expected for several months. Nonetheless, the final decision and its implementation by FERC and the RTOs and ISOs, could be material toExelon, 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 purposesof 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 rateschedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines thatGeneration, ComEd, PECO or BGE has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to orderrefunds 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 poweranalyses using the prescribed market share screens to demonstrate that Generation, ComEd, PECO and BGE qualify for market-based rates inthe 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. OnDecember 21, 2012, Generation, ComEd, PECO, and BGE filed their updated market power analysis for the SPP region, which the FERCaccepted 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 marketpower 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 monthsahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2018 occurred in May 2014. 285Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 itsannual capacity auction at the FERC which is required to include documentation regarding the competitiveness of the auction. Consistent with thisrequirement, on February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 30, 2018delivery 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 filingsbecame effective by operation of law pursuant to a notice issued by the FERC’s secretary on September 16, 2014. Several parties soughtrehearing 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 Courtof Appeals. It is not clear whether such appeal would be effective as there is no action by the Commission to be considered. Nonetheless, whilewe think any change in the auction results to be unlikely, Exelon and Generation cannot predict with certainty what further action the court maytake concerning the results of that auction, but any court action could be material to Exelon’s and Generation’s expected revenues from thecapacity auction. License Renewals (Exelon and Generation). In June 2012, the United States Court of Appeals for the DC Circuit vacated the NRC’stemporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. Thetemporary storage rule (also referred to as the “waste confidence decision”) recognized that licensees can safely store spent nuclear fuel atnuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do notrequire discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewedoperating licenses that depend on the temporary storage rule until the court’s decision is addressed. On August 26, 2014, the NRC Commissionersapproved the issuance of a revised rule codifying the NRC’s generic determinations regarding the environmental impacts of continued storage ofspent nuclear fuel beyond a reactor’s licensed operating life and removed the hold on final licensing decision as of the effective date of the finalrule. 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 variousfederal 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 ruleand GEIS. On May 29, 2013, Generation submitted applications to the NRC to extend the current operating licenses of Byron Units 1 and 2, which arecurrently set to expire in 2024 and 2026, respectively, and Braidwood Units 1 and 2, currently set to expire in 2026 and 2027, respectively, by 20years. 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 2044and 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 until2016 at the earliest. 286Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theConowingo 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 toSection 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditionsthat ultimately may be imposed. MDE indicated that it believed it did not have sufficient information to process Generation’s application. As aresult, on December 5, 2014, Generation withdrew its pending application for a water quality certification. FERC policy requires that an applicantresubmit its request for a water quality certification within 90 days of the date of withdrawal. Accordingly, Generation is working with MDE tocoordinate the refiling of its application for certification within the 90-day period. In addition, Generation has entered into an agreement with MDE towork with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center forEnvironmental 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 toConowingo may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in capitalexpenditures 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 anecessary step in the FERC licensing process and included certain commitments made by Generation. The financial impact associated with thesecommitments 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 isrequired to issue annual licenses for the facilities until the new licenses are issued. On September 10, 2014, FERC issued annual licenses forConowingo and Muddy Run, effective as of the expiration of the previous licenses. If FERC does not issue new licenses prior to the expiration ofannual licenses, the annual licenses will renew automatically. The stations are currently being depreciated over their estimated useful lives, whichincludes 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 foraccounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of theirprobable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued creditsthat have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings inadvance of expenditures for approved regulatory programs. 287Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 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(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 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 ofReceivable 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 Programof $27 million and $0 million, respectively. 289(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 regulatoryliabilities of $88 million related to ComEd’s and BGE’s portion of deferred costs associated with Exelon’s pension plans and ComEd’s, PECO’sand BGE’s portion of deferred costs associated with Exelon’s other postretirement benefit plans. PECO’s pension regulatory recovery is based oncash contributions and is not included in the regulatory asset (liability) balances. The regulatory asset (liability) is amortized in proportion to therecognition of prior service costs (gains), transition obligations and actuarial losses (gains) attributable to Exelon’s pension and otherpostretirement 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 pensionand other postretirement benefit regulatory asset balance includes a regulatory asset established at the date of the Constellation merger related toBGE’s portion of the deferred costs associated with legacy Constellation’s pension and other postretirement benefit plans. The BGE-relatedregulatory asset is being amortized over a period of approximately 12 years, which generally represents the expected average remaining serviceperiod of plan participants at the date of the Constellation merger. See Note 16—Retirement Benefits for additional detail. No return is earned onExelon’s regulatory asset. Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of incometaxes and how income taxes would be recorded under GAAP. Regulatory assets and liabilities associated with deferred income taxes, recorded incompliance with the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effectsassociated principally with accelerated depreciation accounted for in accordance with the ratemaking policies of the ICC, PAPUC and MDPSC, aswell as the revenue impacts thereon, and assume continued recovery of these costs in future transmission and distribution rates. For ComEd andBGE, this amount includes the impacts of a reduction in the deductibility, for Federal income tax purposes, of certain retiree health care costspursuant to the March 2010 Health Care Reform Acts. ComEd was granted recovery of these additional income taxes on May 24, 2011 in theICC’s 2010 Rate Case order. The recovery period for these costs was through May 31, 2014. For BGE, these additional income taxes are beingamortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. For PECO, this amount includesthe 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 regulatoryasset in base rates. AMI programs. For ComEd, this amount represents operating and maintenance expenses and meter costs associated with ComEd’s AMIpilot program approved in the May 24, 2011, ICC order in ComEd’s 2010 rate case. The recovery periods for operating and maintenance expensesand meter costs through May 31, 2014, and January 1, 2020, respectively. As of December 31, 2014 and December 31, 2013, ComEd hadregulatory 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 areturn on the regulatory asset. For PECO, this amount represents accelerated depreciation and filing and implementation costs relating to thePAPUC-approved Smart Meter Procurement and Installation Plan as well as the return on the un-depreciated investment, taxes, and operating andmaintenance 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 January2011 on full and current basis, which includes interest income or expense on the under or 290Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 periodending December 31, 2020. For BGE, this amount represents smart grid pilot program costs as well as the incremental costs associated withimplementing full deployment of a smart grid program. Pursuant to a MDPSC order, pilot program costs of $11 million were deferred in a regulatoryasset, and, beginning with the MDPSC’s March 2011 rate order, is earning BGE’s most current authorized rate of return. In August 2010, theMDPSC approved a comprehensive smart grid initiative for BGE, authorizing BGE to establish a separate regulatory asset for incremental costsincurred to implement the initiative, including the net depreciation and amortization costs associated with the meters, and an authorized rate ofreturn on these costs, a portion of which is not recognized under GAAP until cost recovery begins. Additionally, the MDPSC order requires thatBGE 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 excludescosts for non-AMI meters being replaced by AMI meters, as recovery of those costs commenced with the new rates approved and implementedwith 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, DOEreimbursements and amounts recovered from the vendor, of smart meter deployment that will no longer be used, including installation and removalcosts. 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 onapplicable case law and past precedent on reasonably and prudently incurred costs. As such, PECO deferred these costs on Exelon’s andPECO’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 lossimpacts on future results of operations. Under-recovered distribution services costs. Under EIMA, ComEd is allowed recovery of distribution services costs through a formularate tariff. The legislation provides for an annual reconciliation of the revenue requirement in effect to reflect the actual costs that the ICCdetermines are prudently and reasonably incurred in a given year. The over recovery associated with the 2011 reconciliation was recovered throughrates over a one-year period, that began in January 2013. The under recovery associated with the 2012 reconciliation was recovered through ratesover a one-year period that began in January 2014. The under recovery associated with the 2013 reconciliation will be recovered through rates overa one-year period beginning in January 2015. ComEd is earning a return on these costs. The regulatory asset also includes costs associated withcertain one-time events, such as large storms, which will be recovered over a five-year period. As of December 31, 2014, the regulatory asset wascomprised of $286 million for the applicable annual reconciliations and $85 million related to significant one-time events. In addition to $66 millionin deferred storm costs, net of amortization, the December 31, 2014 balance related to significant one-time events contains $19 million ofConstellation 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 eventscontains $28 million of Constellation merger and integration related costs, net of amortization, incurred as a result of the Constellation merger. SeeNote 4—Mergers, Acquisitions, and Dispositions for additional information. 291Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 debtredemption or over the life of the original debt issuance if the debt is not refinanced. Interest-rate swap settlements are deferred and amortizedover 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 theweighted 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 ofthe 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 therecovery of these costs. Fair value of BGE supply contract. These amounts represent the regulatory asset recorded at Exelon representing the fair value of BGE’ssupply contracts as of the close of the Constellation merger date based on the MDPSC practice to allow BGE to recover its supply contractsthrough rates. Exelon amortized the regulatory asset and the associated fair value through December 31, 2014 and was not earning a return on therecovery of these contracts. Severance. For ComEd, these costs represent previously incurred severance costs that ComEd was granted recovery of in theDecember 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 asof December 31, 2014. ComEd did not earn a return on these costs. For BGE, these costs represent deferred severance costs that BGE haspreviously been granted recovery of in rates. Costs include the portion of costs associated with a 2008 workforce reduction that relate to BGE’sgas business which were deferred in 2009 as a regulatory asset in accordance with the MDPSC’s orders in prior rate cases and are beingamortized over a 5-year period through December 31, 2013. Also included are costs associated with a 2010 workforce reduction that were deferredas 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 rateorder. Finally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance withthe 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 onthe regulatory asset included in base rates. Asset retirement obligations. These costs represent future legally required removal costs associated with existing asset retirementobligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd andBGE will recover these costs through future depreciation rates and will earn a return on these costs once the removal activities have beenperformed. 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 recoverablethrough rates as affirmed in the 2010 approved natural gas distribution rate case settlement. The period of recovery for both ComEd and PECO willdepend on the timing of the actual expenditures. ComEd and PECO are not earning a return on the recovery of these costs. While BGE does nothave a rider for MGP clean-up costs, BGE has historically received 292Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 periodfrom July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates inaccordance 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. ComEdis 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 torecover discounts issued to electric and gas customers enrolled in assistance programs. As of December 31, 2014, PECO was under-recoveredfor its gas program and over-recovered for its electric program. Whereas, as of December 31, 2013, PECO was over-recovered for both its electricand 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 annualuncollectible accounts costs. The recovery or refund of the difference in the uncollectible accounts costs takes place over a 12-month time framebeginning 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 unaffiliatedsuppliers for the procurement of long-term renewable energy. Delivery under the contracts began in June 2012. Since the swap contracts weredeemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period as well as anoffsetting regulatory asset or liability are recorded by ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). The basis forthe mark-to-market derivative asset or liability position is based on the difference between ComEd’s cost to purchase energy on the spot marketand the contracted price. Energy and transmission programs. ComEd’s energy and transmission costs are recoverable (refundable) under ComEd’s ICC and/orFERC-approved rates. ComEd earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As ofDecember 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 andintegration costs to be recovered upon FERC approval. As of December 31, 2014, ComEd’s regulatory liability of $19 million included $3 millionrelated 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 andnon-hourly customers, $17 million associated with transmission costs recoverable through its FERC-approved formula rate, and $6 million ofConstellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2013, ComEd’s regulatory liability of $9million related to revenues received for renewable energy requirements. 293Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 naturalgas 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 GSAunder (over)-recovered energy costs. See discussion below of each program. The PECO transmission costs represent the electric transmissioncosts recoverable (refundable) under the TSC under which PECO earns interest on under-recovered costs and pays interest on over-recoveredcosts to customers. As of December 31, 2014, PECO had a regulatory liability that included $39 million related to the DSP program, $16 millionrelated to over-recovered natural gas supply costs under the PGC and $3 million related to over-recovered electric transmission costs. As ofDecember 31, 2013, PECO had a regulatory liability that included $34 million related to the DSP program, $8 million related the over-recoveredelectric 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, andinformation technology improvements associated with PECO’s PAPUC- approved DSP Program for the procurement of electric supplyfollowing the expiration of PECO’s generation rate caps on December 31, 2010. The filing and implementation costs of this DSP Program arerecoverable through the GSA over its 29-month term that began January 1, 2011. The independent evaluator costs associated withconducting procurements is recoverable over a 12-month period after the PAPUC approves the results of the procurements. Costs relating toinformation technology improvements are recoverable over a 5-year period that began January 1, 2011. PECO earns a return on the recoveryof 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 procurementassociated with PECO’s second PAPUC-approved DSP program for the procurement of electric supply. The filing and procurement of thisDSP Program are recoverable through the GSA over its 24-month term that began June 1, 2013. The independent evaluator costsassociated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results of theprocurements. PECO is not earning a return on these costs. These costs are included within the energy and transmission programs lineitem. The BGE energy costs represent the electric and gas supply related costs recoverable (refundable) from (to) customers under BGE’smarket-based SOS and MBR programs, respectively. BGE does not earn or pay interest on under- or over-recovered costs to customers. As ofDecember 31, 2014, BGE’s regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million ofConstellation 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 $4million 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 February2010. These costs are being amortized over a 5-year period that began in December 2010. BGE is earning a return on this regulatory asset. 294Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 requirementsfor 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 regulatedrates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. The portion ofthis 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 rateincreases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset onits Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as wellas 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, theMDPSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007 toJanuary 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 chargesrelated to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May2007 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 ICCapproved 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 ofits EE&C Plan. PECO does not earn (pay) interest on under (over) collections. PECO began recovering the costs of its Phase I and Phase IIEE&C Plans through a surcharge in January 2010 and June 2013, respectively, based on projected spending under the programs. Phase Irecovery 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 fundscollected are required to be refunded beginning in June 2016. PECO earned a return on the capital investment incurred under Phase I of theprogram. BGE’s Smart Energy Savers Program includes both MDPSC approved demand response and energy efficiency programs. For the BGEPeak Rewards demand response program which began in January 2008, actual marketing and customer bonus costs incurred in the demandresponse program are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the MDPSC. Fixed assetsrelated to the demand response program are recovered over the life of the equipment. Also included in the demand response program are customerbill credits related to BGE’s Smart Energy Rewards program which began in July 2013. Actual costs incurred in the conservation program arebeing 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 thecapital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections. 295®®SMSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 mergertransaction. As a result of the MDPSC’s February 2013 rate order, BGE deferred $8 million related to non-severance merger integration costsincurred 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 inMarch 2013. The recovery of the remaining $4 million was deferred. In the MDPSC’s December 2013 rate order, BGE was authorized to recoverthe remaining $4 million and an additional $4 million of non-severance merger integration costs incurred during 2013. These costs are beingamortized 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 costsrecoverable 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 millionrelated 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 Unitsthat exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trustfund assets, including prospective earnings thereon and any future collections from customers, will be sufficient to fund the associated futuredecommissioning 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 thefuture non-legally required cost of removal of property, plant and equipment which reduces rate base for ratemaking purposes. This liability isreduced as costs are incurred. DLC Program Costs. The DLC program costs include equipment, installation, and information technology costs necessary to implement theDLC Program under PECO’s EE&C Phase I Plans. PECO received full cost recovery through Phase I collections and will amortize the costs as acredit to the income statement to offset the related depreciation expense during the same period through September 2025, which is the remaininguseful 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 theapplication of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-yearperiod. 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 theapplication of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. InSeptember 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. 296Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 tocomply with the requirements of the AEPS Act, which are recoverable on a full and current basis. PECO earns interest on under-recovered costsand 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 thetreatment of the post-test year accumulated depreciation issue in the 2007 Rate Case. As of December 31, 2014, and December 31, 2013, ComEdowed $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, topurchase 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 recoveruncollectible accounts expense from the suppliers. BGE’s tariff provides that receivables are to be purchased at a discount, primarily to recoveruncollectible accounts expense from the suppliers. However, if the discount rate is negative, the tariff provides that the receivable is purchased ata zero discount rate. BGE is currently purchasing certain receivables at a zero discount rate. PECO is required to purchase receivables at facevalue and is permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO, and BGE donot record unbilled commodity receivables under their POR programs. Purchased billed receivables are classified in other accounts receivable, neton Exelon’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchasedreceivables of the Registrants as of December 31, 2014 and 2013. As of December 31, 2014 Exelon ComEd PECO BGE Purchased receivables $290 $139 $76 $75 Allowance for uncollectible accounts (42) (21) (8) (13) Purchased receivables, net $248 $118 $68 $62 As of December 31, 2013 Exelon ComEd PECO BGE Purchased receivables $263 $105 $72 $86 Allowance for uncollectible accounts (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 theprogram. 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 asa 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 incrementaluncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. 297 (a) (b) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 restatedas of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelonname and be headquartered in Chicago. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each shareof PHI common stock. In connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $126million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI as of December 31, 2014, with additionalinvestments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million. The preferred securities are included inOther non-current assets on Exelon’s Consolidated Balance Sheet. PHI has the right to redeem the preferred securities at its option for thepurchase price paid plus accrued dividends, if any. Exelon expects total cash required to fund the acquisition of common stock and preferredsecurities plus other related acquisition costs to total approximately $7.2 billion. As part of the applications for approval of the merger, Exelon andPHI proposed a package of benefits to the PHI utilities’ respective customers, providing for direct investment of more than $100 million with theactual amount and timing of any related payments dependent upon settlement discussions in merger regulatory approval proceedings and theterms 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 FERChave approved the merger of PHI and Exelon. The Federal Communications Commission has also approved the transfer of certain PHIcommunications licenses. On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed byExelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits toACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with anaggregate 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 thefirst 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 ofextending the DOJ review period until 30 days after PHI and Exelon each has certified that it had substantially complied with the request. OnNovember 21, 2014, Exelon and PHI each certified that it had substantially complied with the request. Accordingly, the HSR Act waiting periodexpired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period underthe 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 itsinvestigation. 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. 298Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 dutiesby entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin PHIfrom completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. InSeptember 2014, the parties reached a proposed settlement which is subject to court approval. Final court approval of the proposed settlement isnot 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 andis in the process of negotiating a settlement. Exelon does not believe these suits will impact the completion of the transaction, and they are notexpected 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 $48million related to acquisition and integration costs and $131 million of costs incurred to finance the transaction. The Merger Agreement alsoprovides for termination rights on behalf of both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be requiredto pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the Merger Agreement does not close due to aregulatory failure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities of PHIdescribed above, through the redemption by PHI of the outstanding nonvoting preferred securities for no consideration other than the nominal parvalue 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 assetsales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). On June 11, 2014, Exelonmarketed 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 salesagreements 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 billionsenior unsecured bridge credit facility to support the contemplated transaction and provide flexibility for timing of permanent financing, which hassubsequently 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-taxcash 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 $332million, including net working capital. Generation has elected to account for the transaction as an asset acquisition for federal income taxpurposes. 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 secondquarter of 2015. The generation and solar asset businesses of Integrys are excluded from the transaction. The Purchase Agreement also includesvarious representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature. 299Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theacquisition date through the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimatesand assumptions used include: projected future cash flows (including the amount and timing); discount rates reflecting the risk inherent in thefuture 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 theIntegrys 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 theacquisition agreement was signed and the closing of the transaction resulting in an increase in the fair value of the net assets acquired as of theacquisition date. The after-tax gain is included within Gain on consolidation and acquisition of businesses in Exelon’s and Generation’sConsolidated 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 ComprehensiveIncome for the period from November 1, 2014 to December 31, 2014 were approximately $386 million and $(42) million, respectively. The net lossincludes pre-tax unrealized losses on derivative contracts of $108 million and the bargain purchase gain of $28 million. Exelon and Generationincurred approximately $7 million of merger and integration related costs which are included within Operating and maintenance expense in Exelon’sand 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, awholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (theInitial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial 300Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 andinto Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’sinterest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly ownedsubsidiary 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 fromConstellation 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 agreedto provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment inthe 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 ConsolidatedStatements of Operations and Comprehensive Income for the year ended December 31, 2012: Description PaymentPeriod BGE Generation Exelon Statement of OperationsLocationBGE rate credit of $100 per residential customer Q2 2012 $113 $— $113 RevenuesCustomer investment fund to invest in energy efficiencyand low-income energy assistance to BGE customers 2012 to 2014 — — 114 O&M ExpenseContribution for renewable energy, energy efficiency orrelated projects in Baltimore 2012 to 2014 — — 2 O&M ExpenseCharitable contributions at $7 million per year for 10 years 2012 to 2021 28 35 70 O&M ExpenseState funding for offshore wind development projects Q2 2012 — — 32 O&M ExpenseMiscellaneous tax benefits Q2 2012 (2) — (2) Taxes Other Than IncomeTotal $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 themerger transaction. The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore forGeneration’s competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement that was contingent upon thedeveloper obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating leasebecame 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 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 indevelopment of 285—300MWs of new generation in Maryland, expected to be completed over a period of 10 years. The MDPSC ordercontemplates 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 oracquiring 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 themost likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generatingplant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitmentwhich is included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and ComprehensiveIncome. While this $44 million loss contingency represents Generation’s best estimate of the future obligation, it is reasonably possible thatExelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million overa 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 the300MW commitment. In July 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Marylandsite with at least 120MW of natural gas-fired generation to satisfy one of the commitments to Maryland with achievement of commercial operationexpected 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 the30MW Fair Wind project in western Maryland with achievement of commercial operations expected in 2015. The wind projects will satisfy a portionof the 125MW Tier I land-based renewables commitment. See Note 22—Commitments and Contingencies for additional information. Exelon’s andGeneration’s consolidated financial statements include $185 million and $24 million of capitalized expenditures within Property, plant andequipment, net as of December 31, 2014 and 2013, respectively, and $3 million and $6 million of development costs within Operating andmaintenance expense for the periods ended December 31, 2014 and 2013, respectively, associated with the pursuit of these commitments for newgeneration 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 threeMaryland generating stations and associated assets, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane inBaltimore County, Maryland, to Raven Power Holdings LLC (Raven Power), a subsidiary of Riverstone Holdings LLC. The sale agreement includeda base price with purchase price adjustments based on fuel inventory, working capital, capital expenditures, and timing of the closing, resulting innet proceeds from the sale of approximately $371 million. Decisions by certain market participants to remove themselves from the biddingprocess, combined with the deadlines and limitations on the pool of potential buyers imposed by the merger approval orders, resulted in realizedsales 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 associatedassets. 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 withRaven Power. 302Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 withthe 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 RavenPower’s remediation of environmental contamination or Exelon’s non-compliance with environmental laws or permits prior to the closing date of thesale. Pursuant to the MDPSC merger approval conditions, BGE was restricted from paying any dividend on its common shares through the end of2014, was required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and was not permitted to reduceemployment 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, Generationinadvertently 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 theerror 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, andaccepted Generation’s proposed remediation. Subsequent close examination by Generation of its cost-based bids also revealed the need for someminor adjustments to the cost build up for certain of its PJM units. Generation has coordinated with PJM to determine the impact on Generation’srevenues and the market from this error and these adjustments, and Generation has worked with PJM to reverse the financial impacts. InNovember 2012, Generation reached a settlement with the DOJ regarding this matter. The final resolution did not have a material impact onExelon’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 breachedtheir fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. Similarsuits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote onthe proposed merger until all material information was disclosed and sought rescission of the proposed merger. During the third quarter of 2011, theparties 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 significantestimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting riskinherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned toeach 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. BGEis 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 303Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 notearning a return, the fair values of BGE’s tangible and intangible assets and liabilities subject to these rate-setting provisions are assumed toapproximate their carrying values and, therefore, do not reflect any net adjustments related to these amounts. For BGE’s debt, fuel supplycontracts and regulatory assets not earning a return, the difference between fair value and book value of BGE’s assets acquired and liabilitiesassumed 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 foradditional 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 mostsignificant adjustments to the preliminary valuation amounts having been made to the fair values assigned to the acquired power supply and fuelcontracts, unregulated property, plant and equipment and investments in affiliates. There were no significant adjustments to the purchase priceallocation 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 ofConstellation 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 Generationfollowing the Upstream Merger for the year ended December 31, 2012. Upon closing of the merger, the operations of these Constellationsubsidiaries 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 $3,165million, $3,065 million and $2,091 million and net 304Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theseamounts, 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 regulatoryasset 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 $58million, $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 ConsolidatedStatements of Operations and Comprehensive Income, with the exception of the BGE customer rate credit and the credit facility fees, which areincluded 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. 305Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 themerger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after applying Exelon’s andGeneration’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 ofoperations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results ofoperations of the combined company. Exelon Generation Year Ended December 31, Year Ended December 31, (unaudited) 2012 2011 2012 2011 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 netbook value of approximately $1.8 billion prior to consideration of asset impairments (See Note 8—Impairment of Long-Lived Assets for furtherinformation), for total pre-tax proceeds of approximately $1.8 billion (after-tax proceeds of approximately $1.4 billion), which resulted in cumulativepre-tax gains on sale of approximately $412 million, which are included in Gain (loss) on sales of assets on Exelon’s and Generation’sConsolidated Statement of Operations and Comprehensive Income. The proceeds are expected to be used primarily to finance a portion of theacquisition of PHI. Station Net GenerationCapacity 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 (a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Othercurrent liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. The table below presents the major classes of assets and liabilitiesheld for sale at December 31, 2014. December 31, 2014 Assets: Property, plant and equipment, net $143 Inventory 4 Total assets held for sale $147 Liabilities: Accrued expenses $1 Asset retirement obligations 4 Total liabilities held for sale $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’sand 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 hashistorically had various agreements with CENG to purchase power and to provide certain services. For further information regarding theseagreements, 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 NuclearOperating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiariesand provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclearfleet, subject to EDFI’s rights as a member of CENG (the Integration Transaction). CENG will reimburse Generation for its direct and allocatedcosts for such services. As part of the arrangement, Nine Mile Point Nuclear Station, LLC, a subsidiary of CENG, also assigned to Generation itsobligations 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 generationby 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 ofspecified available cash flows of CENG and, in any event, payable upon the settlement of the Put Option Agreement discussed below (if the putoption is exercised) or payable upon the maturity date of April 1, 2034, whichever occurs first. Immediately following receipt of the proceeds ofsuch 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 FourthAmended and Restated Operating Agreement for CENG on April 1, 2014, pursuant to which, among other things, CENG committed to makepreferred 307(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 untilGeneration 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, exercisablebeginning 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 pricedetermined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value ofEDF’s 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENGOperating Agreement, including Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return, and thevalue of Generation’s rights to other distributions. The beginning of the exercise period will be accelerated if Exelon’s affiliates cease to own amajority of CENG and exercise a related right to terminate the NOSA. In addition, under limited circumstances, the period for exercise of the putoption 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 againstthird-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclearplants 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 MattersAgreement (EMA) that provides for the transfer of CENG employees to Exelon or one of its affiliates and Exelon’s assumption of the sponsorshipof the employee benefit plans (including certain incentive, health and welfare, and postemployment benefit plans, among others) and their relatedtrusts by Exelon as the plan sponsor as of July 14, 2014. The EMA also generally requires CENG to fund the obligation related to pre-transferservice 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 certainspecified 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 agreementpursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to CENG (ExelonSupport Agreement). The Exelon Support Agreement supersedes a previous support agreement under which Generation had agreed to provide upto $205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specifiedcircumstances to provide up to $165 million in additional financial support for CENG. A previous support agreement executed by an affiliate of EDFremains in effect under which the EDF affiliate may be required to provide up to approximately $145 million of financial support for CENG underspecified circumstances. The agreements were executed on April 1, 2014 when the NRC licenses were transferred to Generation. No liability hasbeen 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. FromJanuary 1, 2014, through March 31, 2014, Generation recorded $19 million of equity in losses of unconsolidated affiliates related to its investmentin CENG and recorded $17 million of revenues from CENG. For the twelve months ended December 31, 2013, Generation recorded $9 million ofequity in losses of unconsolidated affiliates related to its investment 308Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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’sConsolidated Financial Statements between CENG and EDF that are considered related party transactions to Generation. As further described inNote 25—Related Party Transactions EDF and Generation had a PPA with CENG under which they purchased 15% and 85% (throughDecember 31, 2014), respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs. BeginningJanuary 1, 2015 and continuing through the life of the respective plants, EDF and Generation will purchase 49.99% and 50.01%, respectively, ofthe 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 informationregarding 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 equitymethod investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s andGeneration’s Consolidated Balance Sheets. As a result of the consolidation, Exelon and Generation recorded a net gain of $261 million within theirrespective Consolidated Statements of Operations and Comprehensive Income. This gain consists of approximately $136 million related to thestep up to fair value basis of our ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing transactionsbetween 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 assumptionsthat are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cashflows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assetsacquired 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 timeperiod 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 maybe 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 thathave been revised include the asset retirement obligation liabilities and related asset retirement costs. These items have been updated with inputsfrom a third party engineering firm with corresponding adjustments recorded in 2014. See Note 15—Asset Retirement Obligations for discussion ofthe impacts of adjustments recorded during 2014 related to updated estimates of the CENG asset retirement obligation liabilities. In the period ofsuch revisions, these and any other material changes to the fair value assessments have resulted in adjustments to the amounts recorded uponconsolidation. In addition, the asset or liability adjustments impacting depreciation and/or accretion expense recorded after the consolidation datehave impacted Generation’s post-consolidation results of operations. No material changes are expected to the fair value of assets and liabilities. 309Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 wererecorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above: Fair Values Exelon andGeneration 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 ofthe fair value of $152 million for certain specified additional distribution rights under the Operating Agreement. In addition, the noncontrollinginterest 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 intereston the Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interest on theConsolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will considerGeneration’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’S net assets. For the year endedDecember 31, 2014, Generation reduced by $13 million the amount of Net income attributable to noncontrolling interests on Exelon’s andGeneration’s Consolidated Statements of Operations and Comprehensive Income. As a result of the consolidation, Exelon’s and Generation’sConsolidated Statements of Operations and Comprehensive Income includes CENG’s incremental operating revenues of $218 million and CENG’snet income, prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $407 million during the year endedDecember 31, 2014. Exelon and Generation incurred integration-related costs of $26 million for the year ended December 31, 2014. The costs incurred areclassified primarily within Operating and maintenance expense in Exelon’s and Generation’s respective Consolidated Statements of Operationsand 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. 310Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 amountof 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 $204 $140 $214 Allowance for uncollectible accounts (311) (60) (84) (100) (67) 2013 Exelon Generation ComEd PECO BGE Unbilled customer revenues $1,151 $584 $201 $161 $205 Allowance for uncollectible accounts (272) (57) (62) (107) (46) (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 receivablesdescribed 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 lossrates 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 expensefor 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 incomecriteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past duebalances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables isrecorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivablebalance 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 areconsistent with the customer accounts receivable methodology discussed in Note 1—Significant Accounting Policies. The allowance foruncollectible accounts balance associated with these receivables at December 31, 2014 of $15 million consists of $1 million, $3 million and $11million 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 thepayment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding asof December 31, 2014 and 2013 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount ofpast due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of theagreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with themethodology discussed in Note 1—Significant Accounting Policies. 311(a) (b)(c)(d)(a) (b)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 1-8 5,947 5,196 Construction work in progress N/A 2,167 1,890 Other property, plant and equipment 5-50 973 1,017 Total property, plant and equipment 66,829 61,043 Less: accumulated depreciation 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 ofthe 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 includesComEd’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 totalaccumulated 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 BGEof $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil andgas 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 (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 1-8 5,947 5,196 Construction work in progress N/A 1,404 1,129 Other property, plant and equipment 6-31 295 400 Total property, plant and equipment 30,557 27,145 Less: accumulated depreciation 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 buildingswas $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 alsoinclude 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% forthe 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 assumethe renewal of the licenses for all nuclear generating stations (except for Oyster Creek) and the hydroelectric generating stations. As a result, thereceipt of license renewals has no impact on the Consolidated Statements of Operations. See Note 3—Regulatory Matters for additionalinformation 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 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 andtotal accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. 313 (a) (b) (c) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 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 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 (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 forcapitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 13—Debt and Credit Agreements for further informationregarding 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 amountmay not be recoverable. In 2014, updates to the long-term fundamental energy prices, which included a thorough evaluation of key assumptionsincluding gas prices, load growth, plant retirements and renewable growth, suggested that the carrying value of certain wind assets with marketprice 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 witha carrying amount of approximately $151 million were written down to their fair value of $65 million and a pre-tax impairment charge of $86 millionwas recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and ComprehensiveIncome. In 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects with marketprice exposure for either all or a portion of the life of the asset may be impaired. Generation concluded that the estimated undiscounted future cashflows and fair value of eleven wind projects, primarily located in West Texas and Minnesota, were less than their respective carrying values atSeptember 30, 2013. As a result, long-lived assets held and used with a carrying amount of approximately $75 million were written down to theirfair value of $32 million and a pre-tax impairment charge of $43 million, net of the impairment amount attributable to noncontrolling interests forcertain of the projects, was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operationsand Comprehensive Income. In 2014, certain non-nuclear generating assets were identified as assets held for sale on Exelon’s and Generation’s Consolidated BalanceSheets. When long-lived assets are held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds itsestimated 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’sConsolidated 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 thetransaction, Exelon and Generation recorded a pre-tax impairment charge of $272 million to reflect the difference between the sales price and thecarrying value of the generating stations, which was included in Operating and maintenance expense in Exelon’s and Generation’s ConsolidatedStatements of Operations and Comprehensive Income. See Note 4—Mergers, Acquisitions, and Dispositions for further information on asset sales. 315Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 inOklahoma and Texas, were less than their respective carrying values at December 31, 2014. As a result, long-lived assets with a combined netbook value of approximately $163 million were written down to their fair value of $39 million and a pre-tax impairment charge of $124 million wasrecorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and ComprehensiveIncome. After reflecting the impairment, Generation has $189 million of Upstream assets remaining on its Consolidated Balance Sheets atDecember 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 inthe 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 certainprojects. The Measurement Uncertainty Recapture (MUR) uprate projects at the Dresden and Quad Cities nuclear stations were cancelled as aresult 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 extendedpower uprate projects at the LaSalle and Limerick nuclear stations. During 2013, Generation recorded a pre-tax charge to Operating andmaintenance expense and Interest expense of approximately $111 million and $8 million, respectively, to accrue remaining costs and reverse thepreviously 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 leaseslocated in Georgia and Texas with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part ofthe transaction. See Note 14—Income Taxes for further information. For financial accounting purposes, the investments are accounted for asdirect financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, specialpurpose companies it directly or indirectly wholly owns. The lease agreements provide the lessees with fixed purchase options at the end of thelease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to operate the stations and keep or market the poweritself 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 willbe 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 thescheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is lessthan the expected remaining useful life of the plants and, therefore, Exelon’s 316Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofthe lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimumscheduled 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 onthe generating station located in Texas, as described above, prior to its expiration dates. As a result of the lease termination, UII received a netearly termination amount of $335 million from CPS and wrote down the net investment in the CPS long-term lease of $336 million in Investments inExelon’s Consolidated Balance Sheets in 2014; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense inthe 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 leaseinvestments at least annually and record an impairment charge if the review indicates an other than temporary decline in the fair value of theresidual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments underthe 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 thelease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variablecosts, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful lives of the plants. The estimated fair valuesalso reflect the cash flows associated with the service contract option discussed above given that a market participant would take intoconsideration 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 Georgiagenerating 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 impairmentcharges were recorded in Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheets and the ConsolidatedStatements of Operations and Comprehensive Income, respectively. Changes in the assumptions described above could potentially result in futureimpairments of Exelon’s direct financing lease investments, which could be material. Through December 31, 2014, no events have occurred thatwould require Exelon to review the estimated residual values of its direct financing lease investments subsequent to the review performed in thesecond 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 317Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 atDecember 31, 2014 and 2013 were as follows: Nuclear generation Fossil fuel generation Transmission Other Quad Cities PeachBottom Salem Nine MilePoint Unit2 Keystone Conemaugh Wyman PA DE/NJ Other Operator Generation Generation PSEGNuclear Generation GenOn GenOn FP&L FirstEnergy PSEG Ownership interest 75.00% 50.00% 42.59% 82.00% — — 5.89% Various 42.55% 44.24% Exelon’s share atDecember 31, 2014: Plant $995 $1,095 $531 $676 $— $— $3 $14 $64 $2 Accumulateddepreciation 266 343 150 14 — — 3 7 34 1 Construction work inprogress 15 133 29 48 — — — — — — Exelon’s share atDecember 31, 2013: Plant $941 $883 $501 $— $725 $399 $3 $14 $64 $2 Accumulateddepreciation 226 326 134 — 268 220 3 7 34 1 Construction work inprogress 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, 2014and 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 Salemnuclear 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 interestin 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 financialstatements. 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 notrepresent 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 foras if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO’s and BGE’s share of direct expenses of the jointlyowned plants are included in Purchased power and fuel and Operating and maintenance expenses on Exelon’s and Generation’s ConsolidatedStatements of Operations and Comprehensive Income and in Operating and maintenance expenses on PECO’s and BGE’s ConsolidatedStatements of Operations and Comprehensive Income. 318(a)(g)(f)(f)(b)(c)(d)(e)(e)(e)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 endedDecember 31, 2014 and 2013 were as follows: ComEd Generation Exelon Gross Amount AccumulatedImpairment Losses CarryingAmount GrossAmount CarryingAmount GrossAmount AccumulatedImpairmentLosses CarryingAmount 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 orcircumstances change that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. Under theauthoritative guidance for goodwill, a reporting unit is an operating segment or one level below an operating segment (known as a component) andis the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes abusiness for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd hasa single operating segment for its combined business. There is no level below this operating segment for which operating results are regularlyreviewed 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 thereporting 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 thefair 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 thatits 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 ofthe reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step isperformed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order todetermine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded asa reduction to goodwill and a charge to operating expense. Any goodwill impairment charge at ComEd will affect Exelon’s consolidated results ofoperations. ComEd’s valuation approach is based on a market participant view, pursuant to authoritative guidance for fair value measurement, andutilizes a weighted combination of a discounted cash flow 319 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 thegenerally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residualcash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capitalof 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 fairvalue include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows fromComEd’s business and the fair value of debt. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reportingunits to Exelon’s enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multipleanalysis. 2014 Goodwill Impairment Assessment. Pursuant to authoritative guidance, ComEd is required to test its goodwill for impairment annuallyand more frequently if an event occurs or circumstances change that suggest an impairment is more likely than not. ComEd performed aqualitative assessment as of November 1, 2014, for its 2014 annual goodwill impairment assessment and determined that its fair value was notmore likely than not less than its carrying value. Therefore, ComEd did not perform a quantitative assessment. As part of its qualitativeassessment, ComEd evaluated, among other things, management’s best estimate of projected operating and capital cash flows for ComEd’sbusiness as well as changes in certain market conditions, including the discount rate and EBITDA multiples, while also considering the passingmargin 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 chargeto ComEd’s earnings in the first quarter of 2013 triggered an interim goodwill impairment assessment and, as a result, ComEd tested its goodwillfor impairment as of January 31, 2013. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to itscarrying 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 ofthe annual impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairmentof 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 fromany unfavorable impacts of the after-tax interest amounts related to the like-kind exchange position on ComEd’s equity. While neither the interimnor the annual assessments indicated an impairment of ComEd’s goodwill, certain assumptions used to estimate the fair value of ComEd arehighly sensitive to changes. Adverse regulatory actions, such as early termination of EIMA, or changes in significant assumptions, includingdiscount 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 theannual goodwill test performed as of November 1, 2013, the estimated fair value of ComEd would have needed to decrease by more than 10% forComEd to fail the first step of the impairment test. 320Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 impairmentassessment and, as a result, ComEd tested its goodwill for impairment as of May 31, 2012. The first step of the interim impairment assessmentcomparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the secondstep was not required. ComEd performed a qualitative assessment as of November 1, 2012, for its 2012 annual goodwill impairment assessmentand determined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform a quantitativeassessment. As part of its qualitative assessment, ComEd evaluated, among other things, management’s best estimate of projected operatingand 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: WeightedAverageAmortizationYears Gross AccumulatedAmortization Net Estimated amortization expense 2015 2016 2017 2018 2019 Exelon and Generation Unamortized Energy Contracts Exelon Wind 18.0 $224 $(55) $169 $14 $14 $14 $14 $14 Antelope Valley 25.0 190 (12) 178 8 8 8 8 8 Constellation 1.5 1,499 (1,451) 48 19 (31) (21) 11 8 CENG 1.7 (97) 29 (68) (20) (11) (15) (18) (15) Integrys 2.4 6 (5) 1 (8) 6 1 1 — Customer Relationships Constellation 12.4 214 (58) 156 18 18 18 18 17 Integrys 10.0 48 (1) 47 5 5 5 5 5 Trade Names Constellation 10.0 243 (79) 164 23 23 23 23 23 ComEd Chicago settlement—1999 agreement 21.8 100 (79) 21 3 3 4 4 4 Chicago settlement—2003 agreement 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 unamortizedenergy 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 windcapacity 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, CAfrom 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, ComEdagreed 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 theremaining term of the franchise agreement, which ends in 2020. 321(h)(a)(b) (c)(d)(e)(d)(d)(d)(d)(f)(g)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 settlementagreement 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 asa 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 thesettlement, 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 receivedpayments 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 theCity 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 andComEd’s Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of thefranchise 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 endedDecember 31, 2014, 2013 and 2012: For the Year Ended December 31, Exelon Generation 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. AtGeneration, 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 applicationof 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 themarket approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices andother 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 uponcertain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs includeforecasted power and fuel prices and the discount rate. The Exelon Wind unamortized energy contracts are amortized on a straight line basis overthe period in which the associated contract revenues are recognized as a decrease in Operating revenue within Exelon’s and Generation’sConsolidated Statement of Operations and Comprehensive Income. In the case of Antelope Valley, Constellation, CENG and Integrys, the fairvalue amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition datesthrough either Purchase power and fuel expense or Operating revenues within Exelon’s and Generation’s Consolidated Statement of Operationsand Comprehensive Income. 322(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 incomeapproach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the currentcustomer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The fairvalue is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Keyassumptions include the customer attrition rate and the discount rate. The accounting guidance requires that customer-based intangibles beamortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the customer relationships isrecorded in Depreciation and amortization expense within Exelon’s and Generation’s Consolidated Statements of Operations and ComprehensiveIncome. Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach wherebyfair value is determined to be the present value of the license fees avoided by owning the assets. The fair value is based upon certainunobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the hypotheticalroyalty rate and the discount rate. The Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years. Theamortization of the trade name is recorded in Depreciation and amortization expense within Exelon’s and Generation’s Consolidated Statements ofOperations 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 otherassets on the Consolidated Balance Sheets, include RECs (Exelon, Generation and ComEd) and AECs (Exelon and PECO). Purchased RECs arerecorded 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 thecost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contractinception. Revenue for RECs that are part of a bundled power sale is recognized when the power is produced and delivered to the customer. As ofDecember 31, 2014, and 2013, PECO had current AECs of $13 million and $19 million, respectively. PECO had no noncurrent AECs and $5million 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, hadcurrent RECs of $4 million and $3 million, respectively. See Note 3—Regulatory Matters and Note 22—Commitments and Contingencies foradditional information on RECs and AECs. 323Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Short-term liabilities $463 $3 $448 $12 $463 $344 $344 Long-term debt (including amounts due withinone 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 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Short-term liabilities $36 $— $24 $12 $36 $22 $22 Long-term debt (including amounts due within oneyear) 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 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Short-term liabilities $304 $— $304 $— $304 $184 $184 Long-term debt (including amounts due within oneyear) 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 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total 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 324Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) BGE December 31, 2014 December 31, 2013 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total 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 currentliabilities) (Level 1), short-term borrowings (Level 2) and third party financing (Level 3). The Registrants’ carrying amounts of the short-termliabilities 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 aconventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk ofthe Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debtsecurities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondarymarket, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to theappropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then convertedinto 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 valueof 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, (Level3) 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 theproject 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 tothe 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 thelack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasuryrate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a quarterly basisand 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 disposalof SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNFobligation 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 samemethodology as described above for the taxable debt securities, and an estimated maturity date of 2025. 325Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 thefinancing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, andcircumstances 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 valuemeasurements. 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 asof the reporting date. • Level 2—inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectlyobservable 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 orno 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 categorizedwithin 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 2generally occur due to changes in market liquidity or assumptions for certain commodity contracts. There were no transfers between Level 1 andLevel 2 during the year ended December 31, 2014 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for ZionStation decommissioning, Rabbi trust investments, and deferred compensation obligations. 326Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 BalanceSheets 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 $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 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 decommissioningsubtotal 11 121 184 316 11 121 184 316 Rabbi trust investments Cash equivalents — — — — 1 — — 1 Mutual funds 16 — — 16 46 — — 46 Rabbi trust investments subtotal 16 — — 16 47 — — 47 327 (a)(b) (c) (d) (e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 (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 assetssubtotal 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 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 liabilitiessubtotal 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 (f) (f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 $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 fundssubtotal 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 decommissioningsubtotal 61 278 112 451 61 278 112 451 Rabbi trust investments Cash equivalents — — — — 2 — — 2 Mutual funds 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 (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 (a) (b) (c) (d) (e) (f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 assetssubtotal — 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 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 liabilitiessubtotal — (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 anddividend 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 $11million 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 ExecutiveRetirement 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, $800million 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/fromcounterparties, 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(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 arecurring 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 — — — — 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 — — (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 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 — — (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 (a)(b)(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theyear ended December 31, 2014 and 2013: Generation ComEd Exelon For The Year EndedDecember 31, 2014 NuclearDecommissioningTrust FundInvestments Pledged Assetsfor Zion StationDecommissioning Mark-to-MarketDerivatives OtherInvestments TotalGeneration Other-ComEd Eliminated inConsolidation 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 — 532 — — 532 Included in noncurrent payables toaffiliates 14 — — — 14 — (14) — Included in payable for Zion Stationdecommissioning — 2 — — 2 — — 2 Included in regulatoryassets/liabilities — — — — — (14) 14 — Change in collateral — — 198 — 198 — — 198 Purchases, sales, issuances andsettlements Purchases 400 120 76 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 inincome attributed to the change inunrealized gains (losses) related toassets and liabilities as ofDecember 31, 2014 $4 $— $640 $— $644 $— $— $644 332(b)(a)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Generation ComEd Exelon For The Year EndedDecember 31, 2013 NuclearDecommissioningTrust FundInvestments Pledged Assetsfor Zion StationDecommissioning Mark-to-MarketDerivatives OtherInvestments TotalGeneration Other-ComEd Eliminated inConsolidation 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) — (49) — 7 (42) Included in other comprehensive income — — (219) 2 (217) — 219 2 Included in noncurrent payables toaffiliates 8 — — — 8 — (8) — Included in payable for Zion Stationdecommissioning — — — — — — — — 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 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 incomeattributed to the change in unrealized gains(losses) related to assets and liabilities held asof 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 energyswap 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 yearended December 31, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements. 333(d) (b)(f)(a)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 yearended 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 forLevel 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2014 and 2013: Generation Exelon OperatingRevenues PurchasedPower andFuel Other,net OperatingRevenues PurchasedPower andFuel Other,net Total gains (losses) included in net income for the yearended December 31, 2014 $614 $(88) $6 $614 $(88) $6 Change in the unrealized gains (losses) relating to assetsand liabilities held for the year ended December 31,2014 $663 $(23) $4 $663 $(23) $4 Generation Exelon OperatingRevenues PurchasedPower andFuel Other,net OperatingRevenues PurchasedPower andFuel Other,net Total gains (losses) included in net income for the yearended December 31, 2013 $(158) $107 $2 $(152) $108 $2 Change in the unrealized gains relating to assets andliabilities 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 ofthree months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and moneymarket funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1in the fair value hierarchy. Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). Thetrust 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 thesecurities that may be held by the trusts. These policies limit the trust funds’ exposures to investments in highly illiquid markets and otheralternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securitiesare considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. 334 (a) (a) (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 pricingservices, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fairvalues of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equitysecurities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only activelytraded 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 inaddition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. Thetrustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a givensecurity 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 derivingsuch 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 incomesecurities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual tradeinformation or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixedincome securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputsand are categorized in Level 3. Equity, balanced and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and holdcertain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held withinthe 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 investprimarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristicsof 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 (theunit 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 optionfor its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determinedusing a combination of valuation models including cost models, market models, and income models. Investments in middle market lending arecategorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuationmodels. 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 equityvaluations 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, privateequity investments have been categorized as Level 3. 335Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, privateequity investments, and real estate investments of approximately $290 million. These commitments will be funded by Generation’s existingnuclear 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 todeferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The investments inthe Rabbi trusts are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of mutual funds. These fundsare maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistentwith Exelon’s overall investment strategy. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability ofthe 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 fairvalue hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-lineexchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained fromsources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated toensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actualtransaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using theBlack 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. Forderivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments arecategorized in Level 2. The Registrants’ derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets withlimited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include anestimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instrumentsare 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 itstargeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest ratelevels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines thecurrent fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted bythe market’s expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterpartycredit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rateswaps are categorized in Level 2 in the fair value hierarchy. See Note 12—Derivative Financial Instruments for further discussion on mark-to-market derivatives. 336Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 allowparticipants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current andnoncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the marketvalue of the participants’ notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based onobservable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they arecategorized 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 theunobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivativesvalued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data isunavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includesassumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputsgenerally 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 chieffinancial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officersrepresenting Exelon’s business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities and isresponsible for approving all valuation procedures at Exelon. Forward price curves for the power market utilized by the front office to manage theportfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit andnonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in itsassessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impactsof 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 marketabilitydiscounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of powerand natural gas, coal purchases, certain transmission congestion contracts, and project financing debt. Generation utilizes various inputs andfactors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about therisks 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. Forwardcommodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. Alllocations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, brokerquotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on anumber of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. 337Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 eachcounterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price is generally due tothe delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are moreliquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlyingpower curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid locationand applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majorityof 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 appliedspread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3power and gas delivery locations is approximately $2.75 and $0.34 for power and natural gas, respectively. Many of the commodity derivatives areshort 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 beclassified as Level 3. See ITEM 7A.—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding thematurity 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 theprocurement of long-term renewable energy and associated RECs. See Note 12—Derivative Financial Instruments for more information. The fairvalue of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. Themodeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor thatincorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to thepositions 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 atDecember 31,2014 ValuationTechnique UnobservableInput Range Mark-to-market derivatives—Economic hedges (Generation) $893 DiscountedCash Flow Forward powerprice $15 - $120 Forward gaspriceVolatility $1.52 - $14.02 Option Model percentage 8% - 257% Mark-to-market derivatives—Proprietary trading (Generation) $(15) DiscountedCash Flow Forward powerprice $15 - $117 Mark-to-market derivatives (ComEd) $(207) DiscountedCash Flow Forward heatrate 8x - 9x Marketabilityreserve 3.5% - 8% Renewablefactor 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 beyondits 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 powerand gas would be approximately $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading. 338 (a)(c)(d)(d) (a)(c)(d) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Type of trade Fair Value atDecember 31, 2013 ValuationTechnique UnobservableInput Range Mark-to-market derivatives—Economic hedges (Generation) $488 DiscountedCash Flow Forward powerprice $8 - $176 Forward gaspriceVolatility $2.98 - $16.63 Option Model percentage 15% - 142% Mark-to-market derivatives—Proprietary trading(Generation) $3 DiscountedCash Flow Forward powerprice $10 - $176 Mark-to-market derivatives (ComEd) $(193) DiscountedCash Flow Forward heatrate 8x - 9x Marketabilityreserve 3.5% - 8% Renewablefactor 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 beyondits 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 powerand 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 significantunobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options isprice volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for longpositions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contractsthat give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for theholder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimateof volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate orrenewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. Assuch, 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). Formiddle market lending, certain corporate debt securities, and private equity investments the fair value is determined using a combination ofvaluation models including cost models, market models and income models. The valuation estimates are based on valuations of comparablecompanies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio companyor its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as otherfactors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparablecompanies 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 thevaluations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is notreasonably available to 339(a)(c)(d)(d) (a)(c)(d)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 anunderstanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess thereasonableness of the valuations. For a sample of its Level 3 investments, Generation reviewed independent valuations and reviewed theassumptions 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 areexposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies andprocedures 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 Registrantsbelieve these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodityprices. Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes infair 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 accountingtreatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, Generation nolonger utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior tothe Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cashflow hedges was frozen in Accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energycommodity occurred. The effect of this decision is that all derivative economic hedges related to commodities are recorded at fair value throughearnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scopeexception 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 accrualmethod of accounting, which is further discussed in Note 22—Commitments and Contingencies. Additionally, Generation is exposed to certainmarket risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketingportfolio, 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 tocommodity price risk. As such, Generation uses a variety of 340Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 andpurchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability infuture cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixingthe price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing theprice of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchasesto supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedgingobjectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locationalsettlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through otherinstruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auctionrevenue 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 andcontracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. Asof 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 expectedgeneration (which reflects the divestiture impact of Quail Run). Expected generation is the volume of energy that best represents our commodityposition in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regardingfuture market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent allhedging products, which include economic hedges and certain non-derivative contracts, including Generation’s sales to ComEd, PECO and BGEto serve their retail load. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements formore detail regarding divestitures. On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for theprocurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC’s Orderon December 19, 2012, ComEd’s commitments under the existing long-term contracts for energy and associated RECs were reduced for the June2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitmentsunder 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 procurementrequirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEdrecords the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and relatedcosts from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3—RegulatoryMatters 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 Programspermitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s 341Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 throughfull requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivativesand 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 underdifferent pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO mustassure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supplyexists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify forthe 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 pricevolatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-inprices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the2014 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commoditypurchases. PECO’s gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. Thehedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs arefully 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 anincremental cost component and a shareholder return component for commercial and industrial rate classes. BGE’s price risk related to electricsupply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s fullrequirements 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 ofgas 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 themarket index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not morethan 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-pricecontracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meetcustomer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result inphysical delivery. Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary tradingincludes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with theintent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary tradingactivities, 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 energymarketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes. 342Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 utilizefixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. Inaddition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designatedas cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2014, Exelon and Generation had $1,450million and $550 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $3,070 million and $770 million of notionalamounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, ahypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floatingswaps would result in an approximate $8 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2014. Tomanage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizesforeign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign exchangehedges as of December 31, 2014: Generation Other Exelon Description DerivativesDesignated asHedgingInstruments EconomicHedges ProprietaryTrading Collateraland Netting Subtotal DerivativesDesignated asHedgingInstruments EconomicHedges CollateralandNetting Subtotal Total Mark-to-marketderivative assets(current assets) $7 $7 $20 $(22) $12 $3 $— $— $3 $15 Mark-to-marketderivative assets(noncurrentassets) 1 5 7 (7) 6 20 1 (19) 2 8 Total mark-to-marketderivative assets 8 12 27 (29) 18 23 1 (19) 5 23 Mark-to-marketderivative liabilities(current liabilities) (8) (2) (14) 25 1 — — — — 1 Mark-to-marketderivative liabilities(noncurrentliabilities) (4) — (9) 10 (3) (29) (101) 19 (111) (114) Total mark-to-marketderivative liabilities (12) (2) (23) 35 (2) (29) (101) 19 (111) (113) Total mark-to-marketderivative netassets (liabilities) $(4) $10 $4 $6 $16 $(6) $(100) $— $(106) $(90) 343(a) (b) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theinterest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity positionthat 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 marketinterest 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 ofDecember 31, 2013: Generation Other Exelon Description DerivativesDesignated asHedgingInstruments EconomicHedges ProprietaryTrading Collateraland Netting Subtotal DerivativesDesignated asHedgingInstruments 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 derivativeassets 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 derivativeliabilities (11) (2) (31) 32 (12) (4) (16) Total mark-to-market derivative netassets (liabilities) $15 $4 $(1) $— $18 $3 $21 (a)Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of theinterest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity positionthat 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 marketinterest rates.(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 wellas the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or losson 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 $(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 $2million excluded from hedge effectiveness testing, respectively. 344(a) (b) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 rateswaps, which expire in 2019 and 2020, respectively. At December 31, 2014, Exelon and Generation had total outstanding fixed-to-floating fairvalue hedges related to interest rate swaps of $1,450 million and $550 million, with a derivative asset of $29 million and $7 million, respectively. AtDecember 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 impacton 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—Debtand Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and amandatory early termination date of September 30, 2014. The interest rate swap was designated as a cash flow hedge, and as a result, unrealizedlosses 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 beamortized into Interest expense on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income over the termof 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 tomanage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements foradditional 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 $3million 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 tomanage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements foradditional information regarding the financing. The swap has a notional amount of $26 million as of December 31, 2014, and expires in 2030. Thisswap 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 tomanage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements foradditional information regarding the financing. The swaps have a notional amount of $213 million as of December 31, 2014 and expire in 2020. Theswaps 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 tomanage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 13—Debt and Credit Agreements for additionalinformation regarding the financing. The swaps have a notional amount of $505 million as of December 31, 2014 and expire in 2019. The swap wasdesignated as a cash flow hedge in the fourth quarter of 2014. At December 31, 2014, the subsidiary had a $8 million derivative liability related tothe swap. 345Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 rateexposure 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 flowhedges was immaterial. Economic Hedges. During 2014, Exelon entered into $1,900 million of floating-to-fixed forward starting interest rate swaps to manage aportion 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 riskassociated with the interest rate component of commodity positions and $349 million in notional amounts of foreign currency exchange rate swapsthat 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 beshown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legallyenforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is anagreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of allreferencing 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 thetable below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fairvalue balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateralincluding initial margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2014 and 2013, $8 millionand $10 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated withany energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excludedfrom the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted forunder 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. branchoffice that meet certain qualifications. 346Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 EconomicHedges ProprietaryTrading CollateralandNetting Subtotal EconomicHedges TotalDerivatives Mark-to-marketderivative assets (current assets) $4,992 $456 $(4,184) $1,264 $— $1,264 Mark-to-marketderivative assets (noncurrent assets) 1,821 56 (1,112) 765 — 765 Total mark-to-marketderivative assets 6,813 512 (5,296) 2,029 — 2,029 Mark-to-marketderivative liabilities (current liabilities) (4,947) (468) 5,200 (215) (20) (235) Mark-to-marketderivative liabilities (noncurrent liabilities) (1,540) (64) 1,502 (102) (187) (289) Total mark-to-marketderivative liabilities (6,487) (532) 6,702 (317) (207) (524) Total mark-to-marketderivative 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 derivativetransactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have otheroffsetting 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 andother 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 $1,406million at December 31, 2014.(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. 347 (a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 EconomicHedges ProprietaryTrading CollateralandNetting Subtotal EconomicHedges TotalDerivatives Mark-to-marketderivative assets (current assets) $2,616 $1,476 $(3,364) $728 $— $728 Mark-to-marketderivative assets (noncurrent assets) 1,344 285 (1,060) 569 — 569 Total mark-to-marketderivative assets 3,960 1,761 (4,424) 1,297 — 1,297 Mark-to-marketderivative liabilities (current liabilities) (2,023) (1,410) 3,292 (141) (17) (158) Mark-to-marketderivative liabilities (noncurrent liabilities) (804) (293) 988 (109) (176) (285) Total mark-to-marketderivative liabilities (2,827) (1,703) 4,280 (250) (193) (443) Total mark-to-marketderivative net assets (liabilities) $1,133 $58 $(144) $1,047 $(193) $854 (a)Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivativetransactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have otheroffsetting 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 andother forms of non-cash collateral. These are not reflected in the table above.(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 relatedto 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 atDecember 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 reasonablyprobable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and is reclassified to results ofoperations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation beganrecording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. Approximately $2million of these net pre-tax unrealized gains within Accumulated OCI are expected to be reclassified from Accumulated OCI during the next twelvemonths by Generation. See Note 13—Debt and Credit Agreements for information about reclassifications from Accumulated OCI on interest rateswap activity that occurred after December 31, 2014. 348(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofoperations. The amounts reclassified from Accumulated OCI, when combined with the impacts of the actual physical power sales, result in theultimate recognition of net revenues at the contracted price. Income StatementLocation Total Cash Flow Hedge OCI Activity,Net of Income Tax Generation Exelon Energy-RelatedHedges Total Cash FlowHedges Accumulated OCI derivative gain at January 1, 2013 $532 $368 Effective portion of changes in fair value — 29 Reclassifications from accumulated OCI to net income Operating Revenues (413) (277) Ineffective portion recognized in income Operating Revenues — — Accumulated OCI derivative gain at December 31, 2013 119 120 Effective portion of changes in fair value — (31) Reclassifications from accumulated OCI to net income Operating Revenues (117) (117) Accumulated OCI derivative gain at December 31, 2014 $2 $(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 withComEd 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 forthe 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-taxearnings based on the reclassification adjustment from Accumulated OCI to earnings was a $195 million, $683 million and $1,368 million pre-taxgain, respectively. Given that the cash flow hedges had primarily consisted of forward power sales and power swaps and did not include power andgas options or sales, the ineffectiveness of Generation’s cash flow hedges was primarily the result of differences between the locationalsettlement prices of the cash flow hedges and the hedged generating units. Changes in cash flow hedge ineffectiveness were losses of $5 millionfor 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 adjustmentfrom Accumulated OCI to earnings was a $195 million, $464 million and $747 million pre-tax gain for the years ended December 31, 2014, 2013and 2012, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were losses of $5 million for theyear ended December 31, 2012. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods as allenergy-related cash flow hedge positions were de-designated prior to the Constellation merger date. 349(a)(d)(e)(c)(b)(d)(e)(b)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 incommodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flowhedge 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 incurrencies other than U.S. Dollars. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risksassociated 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 purchasedpower and fuel expense, or interest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Incomeand are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In thetables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassificationto realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative duringthe period. Generation IntercompanyEliminations ExelonCorporate Exelon Year Ended December 31, 2014 OperatingRevenues PurchasedPowerand Fuel InterestExpense Total OperatingRevenues InterestExpense Total Change in fair value of commodity positions $(413) $(194) $— $(607) $— $— $(607) Reclassification to realized at settlement ofcommodity positions 231 (223) — 8 — — 8 Net commodity mark-to-marketgains (losses) (182) (417) — (599) — — (599) Change in fair value of treasury positions 10 — (2) 8 — (100) (92) Reclassification to realized at settlement oftreasury 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(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Generation IntercompanyEliminations ExelonCorporate Exelon Year Ended December 31, 2013 OperatingRevenues PurchasedPowerand Fuel InterestExpense Total Operating Revenues InterestExpense Total Change in fair value of commodity positions $286 $180 $— $466 $(6) $— $460 Reclassification to realized at settlement ofcommodity 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 oftreasury 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 IntercompanyEliminations ExelonCorporate Exelon Year Ended December 31, 2012 OperatingRevenues PurchasedPower and Fuel InterestExpense Total Operating Revenues InterestExpense Total Change in fair value of commodity positions $(362) $215 $— $(147) $(94) $— $(241) Reclassification to realized at settlement ofcommodity 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 oftreasury 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 wererecorded 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 Generationrecognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-marketgains (losses) (before income taxes) relating to mark-to-market activity on commodity derivative instruments entered into for proprietary tradingpurposes and interest rate derivative contracts to hedge risk associated with the interest rate component of underlying commodity positions. Gainsand losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s Consolidated Statements ofOperations and Comprehensive Income and are included in “Net fair value changes 351(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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” representsthe change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents therecognized change in fair value that was reclassified to realized due to settlement of the derivative during the period. Location on IncomeStatement For the Years EndedDecember 31, 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 derivativeinstruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. Forenergy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, whichreduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivablefrom the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, nettingis limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allowfor cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes creditlimits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty creditlimits 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 areexceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit departmentmonitors 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 andreceivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2014. The tables further delineatethat exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figuresin the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure throughRTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 7A.—QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivableswith ComEd, PECO and BGE of $43 million, $29 million and $40 million, respectively. 352Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Rating as of December 31, 2014 TotalExposureBefore CreditCollateral CreditCollateral NetExposure Number ofCounterpartiesGreater than 10%of Net Exposure Net Exposure ofCounterpartiesGreater 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 forwardmarket prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term andare set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to postcollateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecuredcredit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2014, ComEd’s net credit exposure to suppliers wasimmaterial. ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk ismitigated 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’sperformance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount ofunsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible networth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, comparedto the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier isrequired to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by thesuppliers 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 creditrisk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters for additional information. 353(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 creditrisk 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 naturalgas supply and asset management agreements. As of December 31, 2014, PECO had credit exposure of $8 million under its natural gas supplyand 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 riskis 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 definea supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount ofunsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agenciesand the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is theforward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forwardprice curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater thanthe supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s creditexposure is calculated each business day. As of December 31, 2014, BGE had no net credit exposure to 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 procurenatural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied itscustomers’ demands, which are not covered by the gas cost adjustment clause. At December 31, 2014, BGE had credit exposure of $8 millionrelated to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with thosethird-party 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 saleof electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments containprovisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). Theexchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and marginingrequirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating fromeach 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 seniorunsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting ofderivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master nettingagreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be afunction of the facts and circumstances of the situation at the time of the 354Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 offair 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 fullycollateralized (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 $(1,433) $(1,056) Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements 1,140 846 Net Fair Value of Derivative Contracts Containing This Feature $(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 reducesthe 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 offsettingpositions 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 andletters 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 atDecember 31, 2013 for counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ by S&P orBa1 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 and2013, 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 tomaterially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior tomaturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment byExelon 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 swapon 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 fromGeneration. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, whenmarket prices 355(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 creditlimits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, includingGeneration, 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. Underthe terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, underthe terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The RECportion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As ofDecember 31, 2014, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-termREC 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 inthe form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral andcredit support requirements vary by contract and by counterparty. As of December 31, 2014, PECO was not required to post collateral for any ofthese agreements. If PECO lost its investment grade credit rating as of December 31, 2014, PECO could have been required to postapproximately $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 PECOto post collateral. BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not containprovisions 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 theform of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and creditsupport requirements vary by contract and by counterparty. As of December 31, 2014, BGE was not required to post collateral for any of theseagreements. If BGE lost its investment grade credit rating as of December 31, 2014, BGE could have been required to post approximately $79million of collateral to its counterparties. 356Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 andPECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompanymoney pool. Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2014 and 2013: MaximumProgram Size atDecember 31, OutstandingCommercialPaper atDecember 31, Average Interest Rate onCommercial Paper Borrowings forthe Year Ended December 31, Commercial Paper Issuer 2014 2013 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 backstopthe 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 andwere 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 underthese agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge creditfacility 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 creditfacilities in place, at least equal to the amount of its commercial paper program. While the amount of its outstanding commercial paper does notreduce available capacity under a Registrant’s credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceedingthe then available capacity under its credit agreement. 357(a)(b)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 capacityunder their respective credit agreements: Available Capacity atDecember 31, 2014 Borrower Aggregate BankCommitment Facility Draws OutstandingLetters of Credit Actual To SupportAdditionalCommercialPaper 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)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 andwere 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 underthese agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge creditfacility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.(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. PECOdid 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(a) (c)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 bankcommitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The creditagreement expires on March 28, 2019. The credit facility also allows ComEd to request increases in the aggregate commitments of up to anadditional $500 million. Any increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costsincurred 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 creditfacility with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, into May 2019, with theexception of a cumulative amount of $315 million in commitments, which expire in April 2018. Costs incurred to extend these facilities were notmaterial. On October 24, 2014, a $100 million bilateral CENG credit facility was amended and extended for an additional year. This facility has beenutilized 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 facilitydoes 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 doesnot 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 uponeither 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 and100.0 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings 359Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 afacility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratings of theborrower. An event of default under any of the Registrants’ revolving credit facilities would not constitute an event of default under any of the otherRegistrants’ revolving credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness inprincipal amount in excess of $100 million in the aggregate by Generation under its revolving credit facility would constitute an event of defaultunder 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-monthperiod ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changesin working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its projectsubsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2014: Exelon Generation ComEd PECO BGECredit 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 thelenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction andprovide flexibility for timing of permanent financing. The bridge credit facility was subsequently reduced to $3.2 billion as a result of the June 2014debt and equity security issuances discussed below, as well as, the net after-tax proceeds from generating asset divestitures during the secondhalf of 2014. During the year ended December 31, 2014, Exelon recorded $31 million to interest expense in connection with the bridge facility totemporarily finance the PHI acquisition. It is not currently expected that Exelon will be required to draw upon this credit facility to finance theproposed 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 perunit. 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 aportion 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 forwardequity purchase contract which settles in 2017. The junior subordinated notes are expected to be remarketed in 2017. In connection with theremarketing, Exelon may modify the maturity date of the notes to a date earlier than June 1, 2024 but not earlier 360Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 fromfixed to floating. Investors that participate in the remarketing receive the remarketing proceeds and may use those funds to either settle the equityforward upon settlement date or invest in the remarketed debt and use other funds for the share purchase. Exelon intends to use the remarketingproceeds to repay debt issued or for other corporate purposes as soon as practical following such settlements. If the remarketing fails, holders ofthe 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 accruedinterest. 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 aquarterly 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 inaccordance 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 themarket 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 purchasecontract. 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 obligationunder 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 ofjunior subordinated notes were allocated to debt and recorded within Long-term debt on Exelon’s Consolidated Balance Sheet. Additionally, at thetime of issuance, the present value of the contract payments of $131 million were recorded to Long-term debt, representing the obligation to makecontract payments, with an offsetting reduction to Common stock. The obligation for the contract payments will be accreted to interest expenseover the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income. The Long-term debt recordedfor the contract payments is considered a non-cash financing transaction that was excluded from Exelon’s Consolidated Statements of CashFlows. Until settlement of the equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined underthe treasury stock method. 361Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 and2013: Exelon Rates MaturityDate December 31, 2014 2013 Long-term debt Rate stabilization bonds 5.72% — 5.82% 2017 $195 $265 First mortgage bonds 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 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 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, $5million 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(a)(b)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Generation Rates MaturityDate December 31, 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 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, $4million, $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 annualinterest rate of 2.950%, payable semi-annually, commencing July 15, 2015 and due January 15, 2020. The proceeds of the Senior Notes will beused to fund the optional redemption of Exelon’s $550 million, 4.550% Senior Notes due June 15, 2015 and for general corporate purposes. Inaddition to the issuance, Exelon terminated $400 million of floating-to-fixed interest rate swaps that had been designated as cash flow hedges. Asthe original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest paymentsat 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 of2015. 363(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) ComEd Rates MaturityDate December 31, 2014 2013 Long-term debt First mortgage bonds 1.95% — 6.45% 2015 - 2044 $5,829 $5,546 Notes payable and other 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 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 2015through 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 MaturityDate December 31, 2014 2013 Long-term debt First mortgage bonds 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 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(a)(b) (c)(d)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) BGE Rates MaturityDate December 31, 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 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 6,064 3,693 1,634 1,708 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 pledgedas 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, 2031related to a solar construction project in Denver, Colorado. The agreement bears interest at a fixed rate of 5.50% annually with interest payableannually. 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 gasproperties 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(a)(a)(b)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 extendedthrough January 2019. Borrowings under this facility are secured by the Upstream gas properties, and the lenders do not have recourse againstExelon 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 withinterest payable quarterly. As of December 31, 2014, $77 million was outstanding under the facility. The facility includes a provision that requiresthe 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 30MWsolar facility in Sacramento, California. The note bears interest at a variable rate equal to the six-month LIBOR plus 2.25%. Interest is payablequarterly and is secured by the equity interests and assets of the subsidiary. The note is scheduled to mature on December 31, 2030. As ofDecember 31, 2014, $35 million was outstanding. The subsidiary also executed interest rate swaps with an initial notional value of $30 million inorder 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 byDecember 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 requiresGeneration to establish and maintain a reserve fund to be held by Holyoke Solar Cooperative. As of December 31, 2014, Generation was incompliance 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 anonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project becamefully 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 aspread 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 equitycontributions 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 notionalamount of $485 million to mitigate interest-rate risk associated with the financing. As Generation received additional loan advances, itsubsequently entered into a series of fixed-to-floating interest rate swaps to offset portions of the original interest rate hedge. During the thirdquarter of 2014, the original interest rate swap was terminated, consistent with the agreements. See Note 12—Derivative Financial Instruments foradditional information regarding the interest rate swaps associated with Antelope Valley. 366Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 torecover capital used to build a 16MW solar facility in Emmitsburg, Maryland. The note is schedule to mature on September 7, 2030. The notebears 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 equityinterests and assets of the subsidiary. As of December 31, 2014, $34 million was outstanding. The subsidiary also executed interest rate swapsfor an initial notional amount of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $38 million facilityamount, 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, NewMexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. As ofDecember 31, 2014, $592 million was outstanding. In connection with this nonrecourse project financing, Exelon terminated existing interest rateswaps with a total notional amount of $350 million during the third quarter of 2013, and realized a total gain of $26 million upon termination. Thegain 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. ContinentalWind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2014, the Continental Windletter 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 toGeneration for its general business purposes. The loan bears interest at a variable rate equal to LIBOR plus 4.25%, subject to a 1% floor withinterest payable quarterly. EGR indirectly owns Continental Wind. As of December 31, 2014, $282 million was outstanding. In addition to thefinancing, 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 ofthe interest rate exposure in connection with the financing. See Note 12—Derivative Financial Instruments for additional information regardinginterest 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 netproceeds 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, arevolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. Inaddition to the financing, EGTP entered into interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of2.34% 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. 367Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 368Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Generation ComEd PECO BGE U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% Increase (decrease) due to: State income taxes, net of Federal income tax benefit (3.5) 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 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(a)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 forthe 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 themerger, 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 ofDecember 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 taxcredits $(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 taxcredits $(12,372) $(5,845) $(4,132) $(2,404) $(1,798) 370Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 184 184 — — — State State net operating losses and other credit carryforwards 3,141 1,693 — 170 730 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(a)(b)(c)(d)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 deferthe 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, ifrecognized, would decrease the effective tax rate. Exelon and Generation had $788 million and $768 million, respectively, of unrecognized taxbenefits 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 afterthe 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 ofnuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reducedcapital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation andamortization deductions. The IRS disagrees with this position and has disallowed the claims. In November 2008, Generation received a finaldetermination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen’s refund claims. Generation filed a complaint in the UnitedStates Court of Federal Claims on February 20, 2009 to contest this determination. During the first and second quarters of 2013, AmerGen and theDOJ completed and filed cross motions for summary judgment. On September 17, 2013, the Court granted the government’s motion denyingAmerGen’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 theFederal 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. 372Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 significantlyincrease or decrease within the 12 months after the reporting date as a result of completing audits and expected statute of limitation expirationsthat 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 associatedwith 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) inother income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. The Registrants have notaccrued 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 thesale of ComEd’s fossil generating assets. The gain was 373Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theIRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilitieswhich were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2billion 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 assertedthat the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does notrespect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusivetax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase andleaseback 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. TheIRS 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 aSILO. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, Exelon doesnot believe a settlement is possible. Because Exelon believed, as of December 31, 2012, that it was more-likely-than-not that Exelon would prevailin 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 forthe government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison’s deductions stemming from its participationin 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 inlitigation. 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 theConsolidated Edison decision and Exelon’s current determination that settlement is unlikely, Exelon has concluded that subsequent toDecember 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 recordeda non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental stateincome tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of thisamount, 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 millionreceivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the unpaid tax liabilities related tothe uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings ofExelon or ComEd. In addition, ComEd will continue to record non-cash equity contributions from Exelon in the amount of the net after-tax interestcharges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it is unlikely that the IRS’sassertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded. 374Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 onDecember 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 inorder to litigate the issue. The litigation could take three to five years including appeals, if necessary. Decisions in the Tax Court are not controlledby the Federal Circuit’s decision in Consolidated Edison. In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, the potential tax and after-tax interest, exclusive ofpenalties, that could become currently payable as of December 31, 2014 may be as much as $810 million, of which approximately $310 millionwould be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless, and the balance at Exelon. Litigation couldtake several years such that the estimated cash and interest impacts will increase by a material amount. In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electricgeneration properties in exchange for a net early termination amount of $335 million. The termination resulted in a 2014 tax payment ofapproximately $285 million by Exelon, including approximately $155 million by ComEd representing the remaining gain deferred pursuant to thelike-kind exchange transaction. In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon will be required topay 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 taxpayment. 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 costsincurred to repair electric generation assets. Generation will change its method of accounting for deducting repairs in accordance with thisguidance beginning with its 2014 tax year. Generation has calculated that adoption of the new method will result in a cash tax detriment ofapproximately $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 costsassociated with electric transmission and distribution property. ComEd and PECO adopted the safe harbor in the Revenue Procedure for the 2011and 2010 tax years, respectively. For the year ended December 31, 2011, the adoption of the safe harbor resulted in a $35 million reduction toincome tax expense at PECO, while Generation incurred additional income tax expense in the amount of $28 million due to a decrease in itsdomestic production activities deduction, which was reflected in the effective income tax rate reconciliation in 2011 in the plant basis differencesand domestic production activities deduction lines, respectively. For Exelon, the adoption had a minimal effect on consolidated earnings. Inaddition, 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 adecreased 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 safeharbor resulted in a cash tax benefit at BGE in the amount of $27 million. 375Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 settlementfor 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 taxyear. 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 $29million in tax benefit is recorded at PECO, partially offset by an expense recorded at Generation to reflect a reduction in its domestic productionactivities deduction. BGE changed its method of accounting for gas distribution repairs for the 2008 tax year. The IRS is expected to issueindustry guidance in the near future. Exelon, PECO and BGE will determine the financial statement impacts of the gas distribution repair costsaccounting 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 toacquire, produce, or improve tangible property. The Registrants have assessed the financial impact of this guidance and do not expect it to have amaterial impact. Any changes in method of accounting required to conform to the final regulations will be made for the Registrant’s 2014 taxableyear. 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 of2012. 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 ofFederal taxes) for Exelon. Of this, a benefit in the amount of $116 million and $14 million (net of Federal taxes) was recorded for Exelon andGeneration, respectively, for the three months ended March 31, 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the three months ended March 31, 2012. Thelong-term state tax apportionment also was updated in the fourth quarter of 2012, resulting in the recording of a deferred state tax benefit of $3million (net of Federal taxes) for Exelon, and a deferred state tax expense of $7 million (net of Federal taxes) for Generation. There was no changeto 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 apportionmentpolicy, resulting in the recording of a deferred state tax benefit for Exelon and Generation of $28 million (net of Federal taxes) and $40 million (netof 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 theallocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated anamount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any 376Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 partyreceiving the benefit. During 2014, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax SharingAgreement of $55 million and $25 million, respectively. ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under theTax 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 $26million and $27 million, respectively. During 2013, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the TaxSharing Agreement as a result of ComEd’s and BGE’s tax net operating loss generated primarily by the bonus depreciation deduction allowedunder 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 $48million and $9 million, respectively. During 2012, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the TaxSharing Agreement as a result of ComEd’s and BGE’s tax net operating loss generated primarily by the bonus depreciation deduction allowedunder 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 projectsconstructed 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 estimateits decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses aprobability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significantestimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discountrates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on itsreview of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. 377Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 BalanceSheets, from January 1, 2013 to December 31, 2014: Exelon andGeneration 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 4,855 Consolidation of CENG 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 $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 andGeneration’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 foradditional information. During 2014, Generation’s ARO increased by approximately $2.1 billion. The increase is largely driven by the recording of an ARO onExelon’s and Generation’s Consolidated Balance Sheets at fair value, including subsequent purchase accounting adjustments, upon consolidationof CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC ). The change in the ARO was also driven by an increase foraccretion of the obligation and an increase in the estimated costs to decommission Byron, Braidwood, and LaSalle nuclear units resulting from thecompletion of updated decommissioning costs studies received during 2014 as part of the annual assessment. These increases in the ARO werepartially offset by decreases in the ARO due to a reduction in estimated escalation rates, primarily for labor and energy costs. The increase in theARO due to the changes in, and timing of, estimated cash flows was offset within Property, plant and equipment on Exelon’s and Generation’sConsolidated Balance Sheets, aside from an approximate $16 million credit to income, which is included in Operating and maintenance expensewithin 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 estimatedcosts to decommission the Limerick and Three Mile Island nuclear units resulting from the completion of updated decommissioning costs studiesreceived during 2013 and an increase for accretion of the obligation. These increases in the ARO were offset by decreases to the ARO due tochanges in long-term escalation rates, primarily for labor and energy costs, as well as changes in the timing of the future nominal cash flowscoupled 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 wasentirely offset by decreases in Property, plant and equipment within Exelon’s and Generation’s Consolidated Balance Sheets. 378(a)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theirrespective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants throughregulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECOcustomers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files arate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECOunits based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectiblefrom PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections ofapproximately $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 Generationcan seek to collect additional amounts, from utility customers. Apart from the contributions made to the NDT funds from amounts previouslycollected 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 byGeneration, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activitieshave been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be fundedby both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfallof 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, comparedto decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million andup to 5% of any additional shortfalls, would be borne by Generation. No recourse exists to collect additional amounts for any of Generation’s othernuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completedare required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generationrelated 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, CENGis subject to certain conditions pertaining to nuclear decommissioning trust funds that, if met, could possibly result in obligations to makepayments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that therequired decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions aretriggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds fornon-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spentfuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions 379Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 decommissioningactivities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete allrequired 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 incomesecurities. At December 31, 2013, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed incomesecurities. During 2012, the NDT fixed income portfolio completed its transition from solely core fixed income investments to a blend of TreasuryInflation Protected Securities (TIPS), investment-grade corporate credit and middle market lending. There was no change in the equity investmentstrategy. 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 $180 $406 $386 Net unrealized gains on decommissioning trust funds—Non-Regulatory Agreement Units 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 BalanceSheets 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 gainsrelated 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 ConsolidatedStatements 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’sConsolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for theRegulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations andComprehensive Income. Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC thatdictates 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, aregenerally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset ofdecommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment tothe noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded anequal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the expected value of the NDT fund for 380 (a) (b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, thedecommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and theadverse impact to Exelon’s and Generation’s results of operations and financial position could be material. As of December 31, 2014, the NDTfunds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the relateddecommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to isdifferent, 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 orexcess of trust funds necessary for decommissioning the former PECO units, regardless of whether the funds held in the NDT funds are expectedto exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon’sand Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within theConsolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates atGeneration and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable fromGeneration and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’sability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact toExelon’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’sConsolidated 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 andPECO 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 ZionStation, which is located in Zion, Illinois and ceased operation in 1998. Specifically, Generation transferred to ZionSolutions substantially all of theassets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer ofthose assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF and decommission theSNF dry storage facility, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the ZionStation-related NDT funds for costs incurred related to its decommissioning efforts at Zion Station. During 2013, EnergySolutions entered adefinitive acquisition agreement and was acquired by another Company. Generation reviewed the acquisition as it relates to the ASA todecommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activitiesunder the ASA. 381Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT fundswere reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and willcontinue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioningwas replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the valueof 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 payableto ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for theSNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store theSNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associatedwith the SNF dry storage facility. Generation has a liability of approximately $86 million, which is included within the nuclear decommissioningARO at December 31, 2014. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to theDOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNFand decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after thecompletion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following tableprovides 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 292 414 Current portion of payable to Zion Solutions 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 StationNDT 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 caskstorage 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 theLease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station andpenalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the drycask SNF storage facility. To reduce the risk of default by ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used tofund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions and its parent company have also provided aperformance guarantee and EnergySolutions has entered into other agreements that will provide rights and remedies for Generation and the NRC inthe 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. 382 (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 inspecified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using theNRC methodology differ from the ARO recorded on Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in thetype of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to beused, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimumfunding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRCmethodology, 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 ofcosts 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 costestimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current licenselives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of2019 for Oyster Creek); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period ofdecommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECOunits, 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 atDecember 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 AROestimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certainunits, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-levelradioactive waste); (3) the consideration of multiple scenarios where decommissioning activities are completed under three possible scenariosranging from 10 to 70 years after the cessation of plant operations; (4) the assumption plants cease operating at the end of an extended licenselife (assuming 20-year license renewal extensions, except Oyster Creek with an assumed end-of-operations date of 2019); (5) the measurement ofthe obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a periodof 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 of6% 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 thecurrent 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 ofcredit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts areadequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positionmay be significantly adversely affected. 383Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofDecember 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 findingsfrom the NRC Staff’s review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operatingunits. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulationsfor all of its operating units, including Limerick Unit 1. On March 26, 2014, in accordance with a NRC requirement with respect to units involved ina merger or acquisition, CENG submitted its NRC-required decommissioning funding status report as of December 31, 2013 and no additionalfinancial assurance was required. On March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for reactorsthat have been shut down except for Zion Station which is included on a separate report to the NRC submitted by EnergySolutions (see ZionStation Decommissioning above). This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. Therewas no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is inplace for all reactors owned by Generation. During 2014, the operating license for Limerick Unit 1 was extended by 20 years. As a result of thisextension, and the subsequent funding assurance calculation performed by the NRC, it was found that the parent company guarantee was nolonger required and thus the parent guarantee for Limerick Unit 1 will be cancelled effective March 13, 2015. See Note 3—Regulatory Matters foradditional 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 reflectthe 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 ofDecember 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 theimpact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, toaddress 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 itsregulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC assertedthat Generation’s status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRCsays are the minimum amounts required by NRC regulations. The January 31, 2013 letter from the NRC does not take issue with Generation’scurrent funding status, and as reflected in Generation’s April 1, 2013 decommissioning funding status report referenced above, Generationcontinues to provide adequate funding assurance for each of its units. Generation met with the NRC on April 30, 2013 for a pre-decisionalenforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements anddid not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. On May 1, 2014, theNRC issued its final determination. Although the NRC determined that these historical status reports did not provide complete and accurateinformation, the 384Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 correctiveactions to satisfy the NRC Staff’s expectations and issued a Severity Level IV violation, with no monetary penalty. A Severity Level IV violation isthe 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 documentsgenerally relating to Exelon and Generation’s reporting and funding of the future decommissioning of Generation’s nuclear power plants. Exelonand Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from theSEC 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. Inaddition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers fordecommissioning 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 otherdecommissioning-related activities. ComEd, PECO and BGE have AROs primarily associated with the abatement and disposal of equipment andbuildings contaminated with asbestos and PCBs. See Note 1—Significant Accounting Policies for additional information on the Registrants’accounting policy for AROs. 385Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 fromJanuary 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 cashflows 1 (11) — — 12 Development projects 2 2 — — — Accretion expense 18 13 4 1 — Payments (13) (10) (2) — (1) Non-nuclear AROs at December 31, 2013 351 201 101 30 19 Net increase (decrease) due to changes in, and timing of, estimated future cashflows (1) (2) 2 — (1) Development projects 11 11 — — — Accretion expense 15 11 3 1 — Liabilities held for sale (4) (4) — — — Sale of generating assets (20) (20) — — — Payments (6) (3) (2) (1) — Non-nuclear AROs at December 31, 2014 $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 maintenanceexpense. 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 andmaintenance 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 ofthe 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 theARO. 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 forfurther 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 allGeneration, ComEd, PECO, BGE and BSC employees. The table below shows the pension and postretirement benefit plans in which eachoperating 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 otherpostretirement plans are reflected in the disclosures below based on an April 1, 2014 valuation adjusted for subsequent activity. Exelon assumedsponsorship 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 paymentschedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG. Payments receivedfrom CENG related to the funded plans will be contributed to the appropriate benefit trusts. 386 (a)(b) (c)(d) (a)(b) (c)(e)(f)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Operating CompanyName of Plan: Generation ComEd PECO BGE BSCQualified Pension Plans: Exelon Corporation Retirement Program X X X X XExelon Corporation Cash Balance Pension Plan X X X X XExelon Corporation Pension Plan for Bargaining Unit Employees X X XExelon New England Union Employees Pension Plan X Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek X X XPension Plan of Constellation Energy Group, Inc. X X X X XPension Plan of Constellation Energy Nuclear Group, LLC X X XNine Mile Point Pension Plan X XConstellation Mystic Power, LLC Union Employees Pension Plan Including Plan A andPlan B X Non-Qualified Pension Plans: Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan X X X XExelon Corporation Supplemental Management Retirement Plan X X X X XConstellation Energy Group, Inc. Senior Executive Supplemental Plan X X XConstellation Energy Group, Inc. Supplemental Pension Plan X X XConstellation Energy Group, Inc. Benefits Restoration Plan X X XConstellation Nuclear Plan, LLC Executive Retirement Plan X XConstellation Energy Nuclear Plan, LLC Benefits Restoration Plan X XBaltimore Gas & Electric Company Executive Benefit Plan X X XBaltimore Gas & Electric Company Manager Benefit Plan X X XOther Postretirement Benefit Plans: PECO Energy Company Retiree Medical Plan X X X X XExelon Corporation Health Care Program X X X XExelon Corporation Employees’ Life Insurance Plan X X X X XConstellation Energy Group, Inc. Retiree Medical Plan X X X X XConstellation Energy Group, Inc. Retiree Dental Plan X X XConstellation Energy Group, Inc. Employee Life Insurance Plan and Family LifeInsurance Plan X X X X XConstellation Mystic Power, LLC Post-Employment Medical Account Savings Plan X Exelon New England Union Post-Employment Medical Savings Account Plan X Retiree Medical Plan of Constellation Energy Nuclear Group LLC X X XRetiree Dental Plan of Constellation Energy Nuclear Group LLC X X XNine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan forRetired Employees 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 (a) (a) (a) (a) (a) (b) (c) (c) (b)(a) (a) (b) (b) (b) (c) (c) (b) (b) (a) (a) (a) (b) (b) (b) (b) (a) (c) (c) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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-unionemployees 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 underlyingthese 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 balancesheet, with offsetting entries to Accumulated other comprehensive income (AOCI) and regulatory assets (liabilities), in accordance with theapplicable 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 toreflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $35 million and an increase tothe 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 toreflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $13 million and an increase tothe other postretirement benefit obligation of $3 million. Additionally, AOCL increased by approximately $1 million (after tax) and regulatory assetsincreased by approximately $15 million. In April 2014, Exelon announced plan design changes for certain other postretirement benefit plans, which required an interimremeasurement of the benefit obligation for those plans using assumptions as of April 30, 2014, including updated discount rates and assetvalues. The remeasurement resulted in a decrease to Exelon’s non-pension postretirement benefit obligations, regulatory assets, and AOCL ofapproximately $790 million, $240 million, and $259 million (after tax), respectively, and an increase in regulatory liabilities of approximately $125million. The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all planscombined: Pension Benefits OtherPostretirement 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 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 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Pension Benefits OtherPostretirement 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 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 OtherPostretirement 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 estimatedobligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates andactual returns on plan assets. The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets forall pension plans with a PBO or ABO in excess of plan assets. PBO inexcess of plan assets 2014 2013 Projected benefit obligation $18,256 $15,452 Fair value of net plan assets 14,874 13,564 ABO inexcess 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 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 planswere 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 noassumption 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 planassets 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-termrate 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 ofthis remeasurement. The majority of the 2014 other postretirement benefit cost is calculated using an expected long-term rate of return on planassets 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 asof 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, 2014reflect 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 componentsof 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 valuationperformed on April 1, 2014 upon consolidation of CENG. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC for furtherdetails on the consolidation of CENG. The 2014 pension benefit cost for these plans is calculated using an expected long-term rate of return onplan assets of 7.75% and discount rates ranging from 3.60%—4.30%. The majority of the 2014 other postretirement benefit cost for the CENGplans 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 BalanceSheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years endedDecember 31, 2014, 2013 and 2012. Pension Benefits OtherPostretirement 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 — — 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 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 PrescriptionDrug, Improvement and Modernization Act of 2003 (Medicare Modernization Act), enacted on December 8, 2003, introduced a prescription drugbenefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuariallyequivalent to the Medicare prescription drug benefit (Part D subsidy). Management believes the prescription drug benefit provided under Exelon’spostretirement benefit plans meets the requirements for the subsidy. In December 2011, the Company decided that beginning in 2013, it would nolonger 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 theamortization of an actuarial loss. Beginning in 2013, eligible employees are offered an Employee Group Waiver Plan (EGWP), a standard MedicarePart D Plan, with a supplemental “wrap,” which contains a wraparound prescription drug design that allows the company to provide benefits abovethose 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 wouldotherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for the years endedDecember 31, 2014, 2013 and 2012 for all plans combined. Pension Benefits OtherPostretirement Benefits 2014 2013 2012 2014 2013 2012 Changes in plan assets and benefit obligations recognized in AOCI andregulatory 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) $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 milliongain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753million 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 relatedto other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million lossrelated 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 otherpostretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. 391 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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) thathave not been recognized as components of periodic benefit cost at December 31, 2014 and 2013, respectively, for all plans combined: Pension Benefits OtherPostretirement Benefits 2014 2013 2014 2013 Prior service cost (credit) $49 $62 $(963) $(73) Actuarial loss 7,407 6,192 985 474 Total $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 $22million 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 actuarialvaluation of Exelon’s pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2015 and actualclaims activity as of December 31, 2014. The valuation is expected to be completed in the first quarter of 2015 for the majority of the benefitplans. Pension Benefits OtherPostretirement Benefits Prior service cost (credit) $13 $(175) Actuarial loss 562 74 Total $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 andregulatory 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 plansinvolves various factors, including the development of valuation assumptions and accounting policy elections. When developing the requiredassumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs isimpacted by several assumptions including the discount rate applied to benefit obligations, the long-term EROA, Exelon’s expected level ofcontributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipatedrate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expectedremaining service period, the level of compensation and rate of compensation increases, employee age and length of service, among otherfactors. Expected Rate of Return. In selecting the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) thatimpact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset classallocations. 392 (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 offuture improvements in life expectancy. The change was supported through completion of an experience study and supplemental analysesperformed by its actuaries. The change in assumption resulted in increases of $361 million and $117 million in the pension and otherpostretirement benefits obligations, respectively. The following assumptions were used to determine the benefit obligations for the plans at December 31, 2014, 2013 and 2012. Assumptionsused 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% 3.92% 4.90% 4.00% Rate ofcompensationincrease Mortality table RP-2000table withScale BB-2Dimprovements(adjusted) RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements RP-2000table withScale BB-2Dimprovements(adjusted) RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements Health care costtrend on coveredcharges N/A N/A N/A 6.00%decreasingtoultimatetrend of5.00% in2017 6.00%decreasingtoultimatetrend of5.00% in2017 6.50%decreasingtoultimatetrend of5.00% in2017 (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% 3.92% 4.74% 4.90% 4.00% 4.80% Expected returnon plan assets 7.00% 7.50% 7.50% 6.59% 6.45% 6.68% Rate ofcompensationincrease 3.75% 3.75% Mortality table RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements Health care costtrend oncoveredcharges N/A N/A N/A 6.00%decreasing toultimate trendof 5.00% in2017 6.50%decreasing toultimate trendof 5.00% in2017 6.50%decreasing toultimate trendof 5.00% in2017 (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 endedDecember 31, 2014. Certain of the other postretirement benefit plans were 393(a)(b)(c)(a)(b)(c)(a)(b)(c)(a)(b)(c)(d)(d)(d)(d)(d)(d)(e)(f)(e)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, 2014reflect 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’slegacy 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. SeeNote 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 theyear 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 of3.71% 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 populationswith 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 thefollowing 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 plansprovided by employers. One such provision imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over aprescribed threshold will be taxed at a 40% rate. Although the excise tax does not go into effect until 2018, accounting guidance requires Exelon toincorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exeloncontinues to monitor the Department of Labor and IRS for additional guidance. Certain key assumptions are required to estimate the impact of theexcise tax on Exelon’s other postretirement benefit obligation, including projected inflation rates (based on the CPI) and whether pre- and post- 65retiree populations can be aggregated in determining the premium values of health care benefits. Exelon reflected its best estimate of the expectedimpact in its annual actuarial valuation. 394Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 postretirementbenefit plans: Pension Benefits Other Postretirement Benefits 2014 2013 2012 2014 2013 2012 Generation $173 $119 $48 $124 $30 $135 ComEd 122 118 25 125 4 119 PECO 11 11 13 5 20 33 BGE — — — 17 24 12 BSC 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 mergeron 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 contributionrequirements 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 avoidbenefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimumcontribution requirements and participant notification). Additionally, for Exelon’s largest qualified pension plan, until the plan is fully funded on anABO basis, the projected contribution reflects a funding strategy of contributing $250 million. This level funding strategy helps minimize volatility offuture 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 aboveinclude $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 planbenefit payments of $15 million in 2015, of which Generation, ComEd, PECO, and BGE will make payments of $6 million, $1 million, $1 millionand $1 million, respectively. 395 (c)(a) (b) (d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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’smanagement has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, includinglevels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued raterecovery). In 2015, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with theexception of those plans which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefitpayments related to unfunded plans, of approximately $37 million in 2015, of which Generation, ComEd, PECO, and BGE expect to contribute $17million, $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: PensionBenefits OtherPostretirementBenefits 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 applyingmulti-employer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelonplans were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporaterestructuring. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributionsmade since January 1, 2001. Historically, Exelon has allocated the components of pension and other postretirement costs to the subsidiaries inthe legacy Exelon plans based upon several factors, including the measures of active employee participation in each participating unit. Pensionand postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and totalcosts recognized, respectively. Beginning in 2015, Exelon is allocating costs related to its legacy Exelon pension and postretirement benefit plansto its subsidiaries based on both active and retired employee participation and contributions are being allocated based on accounting cost. Theimpact of this allocation methodology change is not material to any Registrant. For legacy CEG and legacy CENG plans, components of pensionand other postretirement benefit costs and contributions have been, and will continue to be, allocated to the subsidiaries based on employeeparticipation (both active and retired). 396Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 benefitplan 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 BGE 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 orBGE 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 2012contractual 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 theConstellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year endedDecember 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 aregulatory 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 planbenefits 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 volatilityof its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the fundedstatus of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of theplans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s other postretirement plans are managed in adiversified 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 asfollows: Pension Plans Percentage of Plan Assetsat December 31, Asset Category Target Allocation 2014 2013 Equity securities 32% 33% 35% Fixed income securities 37% 37 37 Alternative investments 31% 30 28 Total 100% 100% 397(a)(b)(c) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Other Postretirement Benefit Plans Percentage of Plan Assetsat December 31, Asset Category Target Allocation 2014 2013 Equity securities 41% 42% 45% Fixed income securities 34% 34 37 Alternative investments 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 ofsignificant 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 nosignificant 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’sConsolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2014 and 2013: At December 31, 2014 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. governmentcorporations and agencies 1,051 88 — 1,139 Debt securities issued by states of the United States and by politicalsubdivisions of the states — 80 — 80 Corporate debt securities — 3,125 120 3,245 Other — 942 152 1,094 Derivative instruments: 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 (a)(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) At December 31, 2014 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 corporationsand agencies 15 59 — 74 Debt securities issued by states of the United States and by political subdivisions ofthe 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 $5,323 $8,461 $3,477 $17,261 At December 31, 2013 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. governmentcorporations and agencies 908 99 — 1,007 Debt securities issued by states of the United States and by politicalsubdivisions of the states — 88 — 88 Foreign debt securities — 205 — 205 Corporate debt securities — 2,927 41 2,968 Other 5 899 — 904 Derivative instruments: 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(a)(c)(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) At December 31, 2013 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 corporationsand agencies 17 46 — 63 Debt securities issued by states of the United States and by political subdivisions ofthe 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 $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 theseinstruments 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 ormarket 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 itemsconsist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases. 400(a)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 postretirementbenefit plans for the years ended December 31, 2014 and 2013: Hedgefunds Privateequity Realestate Fixedincome 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 (33) (203) (65) — — (301) Transfers into (out of) Level 3 (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 — (1) — — — (1) Balance as of December 31, 2014 $110 $— $116 $— $— $226 401 (a)(b)(c) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) Hedgefunds Privateequity Realestate Fixedincome 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 (3) (157) (38) — — (198) Transfers into (out of) Level 3 (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 (4) — — — — (4) Transfers into (out of) Level 3 (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 andConstellation 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 reasonableperiod 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 allowingredemption 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 otherpostretirement 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 securitiesand money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included inthe 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 foreignmarkets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from directfeeds from 402 (a) (c)(a)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, areprimarily 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 securitiesare 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 astated set of fund objectives, which are consistent with the plans’ overall investment strategy. The values of some of these funds are publiclyquoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized asLevel 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV perfund 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, municipalbonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple pricesfrom pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primaryprice source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and mayuse a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price andthe trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices arederived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fairvalues of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, includingcertain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade informationof 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, whichare maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistentwith Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, thefunds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutualfunds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in activemarkets of the underlying securities. These funds have been categorized as Level 2. Certain fixed income commingled funds are valued using theNAV per fund share, which is based on the valuation of the underlying investments and include significant unobservable inputs. These funds havebeen categorized as Level 3. Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valuedbased on external price data of comparable securities and have been categorized as Level 2. 403Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 tradedon 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 inputssuch as cost, operating results, discounted future cash flows and market based comparable data. Since these valuation inputs are not highlyobservable, 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 enhancereturns 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 agate. For Exelon’s investments that have terms that allow redemption within a reasonable period of time from the measurement date, the hedgefund investments are categorized as Level 2. For investments that have restrictions that may limit Exelon’s ability to redeem the investments atthe 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 estatecommingled 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 fundsusing the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorizedas Level 2. Other real estate funds are funds with a direct investment in a pool of real estate properties. These funds are valued by investmentmanagers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since thesevaluation 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 underapplicable sections of the IRC and allow employees to contribute a portion of their pre-tax and after-tax income in accordance with specifiedguidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matchingcontributions 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 BSC 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 costsare 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, orBGE amounts above. 404(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theamount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable ofoccurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severanceplan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date ifthere 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 theanticipated employee position reductions as a result of the integration of $2 million and $16 million, respectively. The majority of these positionsare corporate and support positions at CENG. On April 1, 2014, the date the NOSA was executed, Generation consolidated the $19 million CENGseverance liability pursuant to the Master Agreement. For the years ended December 31, 2014 and 2013, respectively, Exelon and Generationrecorded severance benefit costs associated with the employee reductions of $3 million and $2 million within Operating and maintenance expensein their Consolidated Statements of Operations and Comprehensive Income. The estimated amount of severance payments associated with thisplan is expected to be approximately $24 million. As of December 31, 2014, management recorded its best estimate of severance benefits, whichcould be adjusted through the completion of the integration process if additional employee position reductions are identified or if employees resignprior 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, 2014Severance Liability Exelon andGeneration Balance at December 31, 2013 $2 Integration of CENG 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 chargesincurred 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 theend 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 resultof the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon has identified 405(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 previouslyidentified for severance but have since accepted another position within Exelon and are no longer receiving a severance benefit. Exelon adjusts itsaccrual 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, 2014and 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 jobreductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, except forthose costs that were capitalized as regulatory assets related to ComEd and BGE: Year Ended December 31, 2012Severance Benefits Exelon Generation ComEd PECO BGE 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 intercompanyallocations 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 foremployees 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 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-timetermination 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(a)(b)(b)(b) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 inthe normal course of business, which were not directly related to the merger with Constellation or with the integration of CENG. These benefits areaccrued 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 theseongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and ComprehensiveIncome: Severance Benefits 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 positionreductions 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 wereoutstanding. 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 sharesand 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 thatwere redeemable at its option at any time for the redemption price established when each series was issued. The redemption premium was treatedas a reduction to Net income to arrive at Net income attributable to common shareholders utilized in the calculation of the earnings per share forExelon. At December 31, 2014 and 2013, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized and theoutstanding 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 rankingprior to or on a parity with the preference stock as to either dividends or distribution of assets, or which would substantially adverselyaffect the contract rights, as expressly set forth in BGE’s charter, of the preference stock, each of which requires the affirmative vote oftwo-thirds of all the shares of preference stock outstanding; and 407(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 shallhave one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of thepreference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaidaccrued dividends. December 31, RedemptionPrice 2014 2013 2014 2013 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. Thewarrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for threewarrants. At December 31, 2014 and 2013, 24,511 and 24,570 shares of common stock, respectively, were reserved for the conversion ofwarrants. 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. Inconnection 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 pricespecified 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 thepayment of cash or shares of its common stock based on the then current market value of 408(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 willbe recorded in Exelon’s consolidated financial statements with respect to the equity offering until settlement of the forward sale agreementsoccurs. If Exelon elected to net share settle the contract as of December 31, 2014, Exelon would have been required to issue 4 million shares. IfExelon elects to cash settle the contract, the transaction costs will be recorded as a charge to earnings in the period in which it becomes probablethat Exelon will cash settle. Otherwise, all transaction costs will be reflected as a reduction to the value of the common stock issued in Exelon’sConsolidated Balance Sheet. The net proceeds received upon settlement are expected to be used to finance a portion of the acquisition of PHIand for general corporate purposes. Until settlement, earnings per share dilution resulting from the forward sales agreement, if any, will bedetermined 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 equityunits. 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 allowedExelon 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 ofcommon stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock optionexercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of the direct cash proceeds from purchases of stockand the tax benefits associated with exercises of stock options. The 2004 share repurchase program had no specified limit on the number ofshares that could be repurchased and no specified termination date. In 2008, Exelon management decided to defer indefinitely any sharerepurchases. Any shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’smanagement. Under the share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion atDecember 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 shareawards. At December 31, 2014, there were approximately 16 million shares authorized for issuance under the LTIP. For the years endedDecember 31, 2014, 2013 and 2012, exercised and distributed stock-based awards were primarily issued from authorized but unissued commonstock shares. The Compensation Committee of Exelon’s Board of Directors changed the mix of awards granted under the LTIP in 2013 by eliminatingstock options in favor of the use of full value shares, consisting of 67% performance shares and 33% restricted stock units. The performanceshare awards granted in 2013 will cliff vest at the end of a three-year performance period. The performance share awards granted in 2012 andearlier had a one-year performance period and vested ratably over three years. To address the reduction in annual award opportunity resulting fromthe transition to a three-year cliff vesting performance period, the Compensation Committee also approved a one-time grant of 409Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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-yearperformance period. These one-time 2013 performance share transition awards will be settled 50% in common stock and 50% in cash, except forawards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain Exelon stock ownership requirementsare satisfied. In addition to this change, in 2013 ComEd and in 2014 PECO and BGE transitioned from Exelon stock-based awards to cash awardprograms with payouts based on the performance of each respective utility. The following tables do not include expense related to these plans asthey 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 andComprehensive Income for the years ended December 31, 2014, 2013 and 2012: Year EndedDecember 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 EndedDecember 31, Subsidiaries 2014 2013 2012 Generation $52 $48 $42 ComEd 7 9 11 PECO 3 5 5 BGE 5 6 5 BSC 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 Constellationon 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 ofStock-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, PECOand BGE amounts above. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2014, 2013 and 2012. 410(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 forperformance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefitrelated to compensation costs. The tax deductions in excess of the benefits recorded throughout the requisite service period are recorded tocommon stock and are included in other financing activities within Exelon’s Consolidated Statements of Cash Flows. The following table presentsinformation regarding Exelon’s tax benefits for the years ended December 31, 2014, 2013 and 2012: Year EndedDecember 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 theLTIP, there were no stock options granted in 2013 or 2014. For all stock options granted through 2012, the exercise price of the stock options isequal 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. Allstock 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 requisiteservice period for stock options is generally four years. However, certain stock options become fully vested upon the employee reachingretirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date ofgrant 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 tablepresents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stockoptions granted for the year ended 2012: Year endedDecember 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 411Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 inconnection 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 stockprice over the previous year. Expected volatility is based on implied volatilities of traded stock options in Exelon’s common stock and historicalvolatility 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 isbased on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected life represents the periodof time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method isappropriate 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 asnecessary. The following table presents information with respect to stock option activity for the year ended December 31, 2014: Shares WeightedAverageExercisePrice(pershare) WeightedAverageRemainingContractualLife(years) AggregateIntrinsicValue 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 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 and2012: Year EndedDecember 31, 2014 2013 2012 Intrinsic value $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(a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 AverageExercise Price(per share) Nonvested at December 31, 2013 847,118 $40.22 Vested (406,197) 40.21 Forfeited (8,886) 55.78 Nonvested at December 31, 2014 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 fullyvested. At December 31, 2014, $1 million of total unrecognized compensation costs related to nonvested stock options are expected to berecognized 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 theservice condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unitissued. The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite serviceperiod for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon theemployee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognizedimmediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimateemployee 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 AverageGrant Date FairValue (per share) Nonvested at December 31, 2013 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 (578,943) 29.17 Nonvested at December 31, 2014 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 fullyvested.(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 and2012 was $28.71, $31.06 and $39.94, respectively. At 413(a)(a)(a) (b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 and2012, Exelon settled restricted stock units with fair value totaling $43 million, $28 million and $25 million, respectively. At December 31, 2014, $59million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remainingweighted-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 commonstock and 50% in cash at the end of the three-year performance period except for awards granted to executive vice presidents and higher officersthat may be settled 100% in cash if certain ownership requirements are satisfied. The performance shares granted prior to 2012 generally vest andsettle 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 awardand 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 remeasuredeach reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based onExelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of theaward, 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 thegraded-vesting method. For performance share and one-time performance share transition awards granted to retirement-eligible employees, thevalue 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 AverageGrant Date FairValue (per share) Nonvested at December 31, 2013 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 (601,215) 28.96 Nonvested at December 31, 2014 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 theyare 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(a)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 remainingweighted-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 $28 $13 Deferred credits and other liabilities 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 ofshares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restrictedstock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic anddiluted earnings per share and shows the effect of the stock options, performance share awards and restricted stock on the weighted averagenumber 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 wasapproximately 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 inthe calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the year ended December 31, 2014since issuance. Additionally, there were no forward units related to the PHI merger not included in the calculation of diluted common sharesoutstanding due to their antidilutive effect for the year ended December 31, 2014 since issuance. Refer to Note 19—Common Stock for furtherinformation 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 ofDecember 31, 2014. In 2008, Exelon management decided to defer indefinitely any share repurchases. 415 (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 endedDecember 31, 2014 and 2013: For the Year EndedDecember 31, 2014 Gains and(Losses) onCash FlowHedges UnrealizedGains and(Losses) onMarketableSecurities Pension andNon-PensionPostretirementBenefit Planitems ForeignCurrencyItems AOCI ofEquityInvestments Total Exelon Beginning balance $120 $2 $(2,260) $(10) $108 $(2,040) OCI before reclassifications (31) (1) (498) (9) 11 (528) Amounts reclassified from AOCI (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 Beginning balance $114 $2 $— $(10) $108 $214 OCI before reclassifications (15) (1) — (9) 11 (14) Amounts reclassified from AOCI (117) — — — (119) (236) Net current-period OCI (132) (1) — (9) (108) (250) Ending balance $(18) $1 $— $(19) $— $(36) PECO Beginning balance $— $1 $— $— $— $1 OCI before reclassifications — — — — — — Amounts reclassified from AOCI — — — — — — Net current-period OCI — — — — — — Ending balance $— $1 $— $— $— $1 416 (a) (b) (a) (b) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) For the Year EndedDecember 31, 2013 Gains and(Losses) onCash Flow Hedges UnrealizedGains and (Losses) onMarketable Securities Pension andNon-Pension PostretirementBenefit Plan items ForeignCurrencyItems AOCI ofEquity Investments Total Exelon Beginning balance $368 $— $(3,137) $— $2 $(2,767) OCI before reclassifications 29 2 669 (10) 101 791 Amounts reclassified from AOCI (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 Beginning balance $512 $— $— $— $1 513 OCI before reclassifications 15 2 — (10) 102 109 Amounts reclassified from AOCI (413) — — — 5 (408) Net current-period OCI (398) 2 — (10) 107 (299) Ending balance $114 $2 $— $(10) $108 $214 PECO Beginning balance $— $1 $— $— $— $1 OCI before reclassifications — — — — — — Amounts reclassified from AOCI — — — — — — 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 (a)(b) (a)(b) (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 and2013. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years endedDecember 31, 2014 and 2013: For the Year Ended December 31, 2014 Details about AOCI components Items reclassified out of AOCI Affected line item in the Statements ofOperations 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 taxGains and (losses) on available for salesecurities Other available securities for sale $(2) $— Other Income and Deductions $(2) $— Net of taxAmortization of pension and other postretirementbenefit plan items Prior service costs $46 $— Actuarial losses (239) — (193) — Total before tax 75 — Tax benefit $(118) $— Net of taxEquity 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 taxTotal Reclassifications $116 $236 Net of tax 418(a) (b) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Affected line item in the Statements ofOperations and Comprehensive Income Exelon Generation Gains and (losses) on cash flow hedges Energy related hedges $464 $683 Operating revenuesOther cash flow hedges (3) — Interest expense 461 683 Total before tax (184) (270) Tax expense $277 $413 Net of taxAmortization of pension and otherpostretirement benefit plan items Prior service costs $(2) $— Actuarial losses (339) — Deferred compensation unit plan (1) — (342) — Total before tax 134 — Tax benefit $(208) $— Net of taxEquity investments Capital activity $(8) $(8) Equity in losses of unconsolidated affiliates (8) (8) Total before tax 3 3 Tax benefit $(5) $(5) Net of taxTotal 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 additionaldetails).(c)Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. 419(a) (b) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 theyears 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 valuationadjustment 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 theCENG 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 thenumber of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was madeeffective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amountof liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims thatcould arise in the event of an incident. As of January 1, 2013, the amount of nuclear energy liability insurance purchased is $375 million for eachoperating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospectiverating 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 singleincident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incidentfor each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactorper incident per year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG’s related liability. 420Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 toindemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) inconnection 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 Generationpossesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The propertyinsurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurancecompany 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 toits members, but Generation cannot predict the level of future distributions or if they will continue at all. NEIL declared a distribution for 2014 and2013, of which Generation’s portion was $18.3 million and $18.5 million respectively. No distributions were declared in 2012. The distributions wererecorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations andComprehensive Income. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospectivepremium obligation). NEIL has never exercised this assessment since its formation in 1973, and while Generation cannot predict the level of futureassessments, or if they will be imposed at all, as of December 31, 2014, the current maximum aggregate annual retrospective premium obligationfor Generation is approximately $319 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability oftheir annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means ofassurance. NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resultingfrom 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 theinsurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. Inthe event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount ofsuch proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-monthperiod from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by allinsureds 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 insurancemaintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne byGeneration. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations andliquidity. 421Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 radioactivewaste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF fromGeneration’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE onemill ($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 tosubmit 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 ofOperations and Comprehensive Income, including Exelon’s share of Salem and net of co-owner reimbursements (not including such fees incurredby CENG). Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposalfees. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE tobegin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet thatdeadline 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 Mountainrepository while the Obama administration devised a new strategy for long-term SNF management. A Blue Ribbon Commission (BRC) onAmerica’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensiverecommendations for creating a safe, long-term solution for managing and disposing of the nation’s spent nuclear fuel and high-level radioactivewaste. In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level RadioactiveWaste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that is planned to be operational in2025. Generation uses the 2025 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nucleardecommissioning asset retirement obligations. The extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry caskstorage at its Dresden, Clinton, Limerick, Oyster Creek, Peach Bottom, Byron, Braidwood, LaSalle, Quad Cities, Ginna, Nine Mile Point, andCalvert Cliffs stations. In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed toreimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage ofSNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Settlement agreements pertaining to Calvert Cliffs and Ginnawere executed during 2011, and Nine Mile Point during 2012, (the “DOE Settlement Agreements”), as amended in 2014 for Calvert Cliffs and NineMile Point, under which the government has agreed to reimburse the costs associated with SNF storage expended or to be expended through 2016as 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, reimbursementrequests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF. 422Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Cumulative cash reimbursements $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 theconsolidation 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 DOEunder the DOE settlement agreements is as follows: December 31, 2014 December 31, 2013 DOE receivable—current $82 $71 DOE receivable—noncurrent 7 — Amounts owed to co-owners (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 amountsowed 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 throughApril 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to deferpayment 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 tothe 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 corporaterestructuring. 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 additionalinformation. Energy Commitments Generation’s customer facing activities include the physical delivery and marketing of power obtained through its generation capacity, andlong-, intermediate- and short-term contracts. Generation maintains an effective supply strategy through ownership of generation assets and powerpurchase and lease agreements. Generation has also contracted for access to additional generation through bilateral long-term PPAs. Theseagreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Several ofGeneration’s long-term PPAs, which have been determined to be operating leases, have significant contingent rental payments that are dependenton the future operating characteristics of the associated plants, such as plant availability. Generation recognizes contingent rental expense when itbecomes probable of payment. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physicaldelivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity tophysically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assetsand 423(a)(b)(a)(b)(a)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 physicalcontracts, 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 marketparticipants who primarily focus on the resale of energy products for delivery. Generation provides for delivery of its energy to these customersthrough firm transmission. At December 31, 2014, Generation’s short- and long-term commitments, relating to the purchases from unaffiliated utilities and others ofenergy, capacity and transmission rights, are as indicated in the following tables: Net Capacity Purchases RECPurchases Transmission RightsPurchases 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 representGeneration’s expected payments under these arrangements at December 31, 2014, net of fixed capacity payments expected to be received (“capacity offsets”) by Generationunder 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 capacitycharges 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 spotmarket 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 ofalternative 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 RPSrequirement. See Note 3—Regulatory Matters for additional information relating to electric generation procurement, alternative energy resourcesand energy efficiency programs. 424(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 $620 $329 $151 $140 $— $— $— Renewable energy and RECs 1,517 75 76 77 78 84 1,127 PECO Electric supply procurement 609 527 82 — — — — AECs 13 2 2 2 2 2 3 BGE Electric supply procurement 1,315 779 448 88 — — — Curtailment services 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-approvedprocurement 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 fromretail 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 torecover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 3—RegulatoryMatters 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 MDPSCapproved 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 additionalinformation. Fuel Purchase Obligations In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossilgeneration. 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 asfollows: Expiration within Total 2015 2016 2017 2018 2019 2020and 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 (a) (b) (c) (d) (e) (f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 andinformation technology, are as follows: Expiration within Total 2015 2016 2017 2018 2019 2020and beyond Exelon $894 $336 $258 $150 $36 $30 $84 Generation 396 163 67 42 30 24 70 ComEd 148 63 77 1 1 1 5 PECO 7 3 4 — — — — BGE 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(a)(b) (c) (c) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 asfollows: Expiration within Total 2015 2016 2017 2018 2019 2020and beyond Letters of credit (non-debt) $1,233 $1,151 $77 $5 $— $— $— Surety bonds 596 545 10 4 1 2 34 Performance guarantees 1,239 472 20 20 20 20 687 Energy marketing contract guarantees 3,220 3,220 — — — — — Lease guarantees 40 — — — — — 40 Nuclear insurance premiums 3,014 — — — — — 3,014 Underwriters discount 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 FinancingIII, $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 guaranteespreviously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having topost 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 netexposure for obligations under commercial transactions covered by these guarantees is approximately $0.6 billion at December 31, 2014, which represents the total amountExelon 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 anydomestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligationthat 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 (a)(b) (c) (d)(e) (f) (g)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 asfollows: Expiration within Total 2015 2016 2017 2018 2019 2020and beyond Letters of credit (non-debt) $1,187 $1,106 $76 $5 $— $— $— Surety bonds 481 468 3 — — — 10 Performance guarantees 458 319 20 20 20 20 59 Energy marketing contract guarantees 1,244 1,244 — — — — — Nuclear insurance premiums 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 guaranteespreviously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having topost other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimatednet exposure for obligations under commercial transactions covered by these guarantees is approximately $0.4 billion at December 31, 2014, which represents the total amountGeneration 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 anydomestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annualretrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurancepremiums. ComEd’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were asfollows: Expiration within Total 2015 2016 2017 2018 2019 2020and beyond Letters of credit (non-debt) $17 $17 $— $— $— $— $— Surety bonds 5 3 — — — — 2 Performance guarantees 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 (a) (b) (c) (d) (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 asfollows: Expiration within Total 2015 2016 2017 2018 2019 2020and beyond Letters of credit (non-debt) $22 $22 $— $— $— $— $— Surety bonds 18 18 — — — — — Performance guarantees 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 asfollows: Expiration within Total 2015 2016 2017 2018 2019 2020and beyond Letters of credit (non-debt) $1 $1 $— $— $— $— $— Surety bonds 11 11 — — — — — Performance guarantees 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 toprovide 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 fullyoperational 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 commitmentis approximately $2 million under the contract and achievement of commercial operations was attained 2014. 429 (a)(b)(c) (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 generationsite with at least 120MW of new natural gas-fired generation. The remaining commitment is approximately $39 million under the contract andachievement 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 inMaryland resulting from the Constellation merger. On December 27, 2013, Generated executed a turbine supply agreement for construction of the 40MW Fourmile Wind project in westernMaryland. The remaining commitment is approximately $2 million under the contract and achievement of commercial operations was attained in2014. 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 Marylandresulting from the Constellation merger. During the third and fourth quarter of 2014, Generation executed contracts associated with the construction of new combined-cycle gasturbine units in Texas. The remaining commitment is approximately $1.0 billion under these contracts and achievement of commercial operationsis expected in 2017. During the fourth quarter of 2014 Generation executed contracts associated with the construction of the 30 MW Fair Wind project in westernMaryland. The remaining commitment is approximately $19 million under these contracts and achievement of commercial operations is expectedin 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 Marylandresulting from the Constellation merger. During the fourth quarter of 2014 Generation executed contracts associated with the construction of the 78 MW Sendero Wind project insouthern Texas. The remaining commitment is approximately $56 million under these contracts and achievement of commercial operations isexpected in 2015. Refer to Note 3—Regulatory Matters for information on investment programs associated with regulatory mandates, such as ComEd’sInfrastructure Investment Plan under EIMA, PECO’s Smart Meter Procurement and Installation Plan, and BGE’s comprehensive smart gridinitiative. 430Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 whichinclude commitments to purchase additional equity through incremental payments. The additional equity is provided by the agreements to fund theanticipated 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 servicescontributions, 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 andoffice equipment, as of December 31, 2014 were: Exelon Generation ComEd PECO BGE 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 $899 $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 disclosedin 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 effectiveduring 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 $285million 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 thesepayments 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 theyears 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(b)(c)(c)(c)(d)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 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 Commitmentstable 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 inSithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group’s 50% interest in Sithe and subsequentlysold 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 wasapproximately $200 million at December 31, 2013. The guarantee expired January 31, 2014. Generation was not required to make payments underthe 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 withenvironmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediatingenvironmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated bythem. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others mayhave resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currentlyinvolved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additionalproceedings in the future. ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. Foralmost 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 and25 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at thesesites 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. Theremaining 10 sites are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation atthese sites to continue through at least 2021. 432(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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’sacquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. Therequired costs at these two sites are not considered material. One gas purification site is in the initial stages of investigation at thedirection 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 currentlyrecovering environmental remediation costs of former MGP facility sites through customer rates. BGE is authorized to recover, and is currentlyrecovering, environmental costs for the remediation of former MGP facility sites from customers; however, while BGE does not have a rider forMGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. ComEd, PECO and BGE have recordedregulatory assets for the recovery of these costs. See Note 3—Regulatory Matters for additional information regarding the associated regulatoryassets. As of December 31, 2014 and 2013, the Registrants have accrued the following undiscounted amounts for environmental liabilities in othercurrent liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets: December 31, 2014 Total environmentalinvestigationand remediation reserve Portion of total related to MGPinvestigation andremediation Exelon $347 $277 Generation 63 — ComEd 238 235 PECO 45 42 BGE 1 — December 31, 2013 Total environmentalinvestigationand remediation reserve Portion of total related to MGPinvestigation andremediation 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 aprecise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Managementdetermines its best estimate of remediation costs based on probabilistic and deterministic modeling using all available information at the time ofeach study and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significantclean 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. Theresults of these studies indicated that additional remediation would be required at certain sites. Accordingly, ComEd and PECO increased theirenvironmental liabilities and related regulatory assets by $26 million and $4 million, respectively, primarily reflecting refined assumptions regardingclean-up techniques and scopes based on additional experience and analysis as site clean-up and investigation activities progress. 433Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofinvestigation and the extent of contamination is not currently known, BGE is unable to estimate actual remediation costs, which may be materialto 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 remediationcosts at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable fromthird parties, including customers. Water Quality Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating togroundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consentdecree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at thesite, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. As of December 31, 2014 and2013, 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 (MidwestGeneration), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumedresponsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility forcompliance by the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionallyagreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third partyclaims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms ofthe agreement governing the sale. In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligationswith 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 specificasbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement forliabilities 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 Chapter11 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 MidwestGeneration had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the partyresponsible for making all remaining payments under the lease and performing all other obligations thereunder. In January 2013, Generation madethe final $10 million payment due under the lease agreement which had been accrued at December 31, 2012. 434Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofReorganization. On April 1, 2014 (Effective Date), NRG Energy purchased EME’s portfolio of generation, including Midwest Generation and theJoint 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 claimsassociated 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 byEME and Midwest Generation related to the coal rail car lease. Further, Exelon filed an environmental claim with an unspecified amount that listedthe 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 carlease 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 suchproperties 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 generationbusiness) 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 availablepublic information as to potential environmental exposures regarding the Midwest Generation station sites. Midwest Generation publicly disclosedin 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 millionfor estimated environmental investigation and remediation costs under CERCLA, or similar laws, for the investigation and remediation ofcontaminated property at two Midwest Generation plant sites, (ii) it has identified stations for which a reasonable estimate for investigation and/ orremediation cannot be made and (iii) it and the Illinois EPA entered into Compliance Commitment Agreements outlining specified environmentalremediation measures and groundwater monitoring activities to be undertaken at its Crawford, Powerton, Joliet, Will County and Waukegangenerating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihoodor magnitude of any remediation requirements that may be asserted. For these reasons, ComEd and Generation are unable to predict whether andto what extent they may ultimately be held responsible for remediation and other costs relating to the generating stations and as a result no liabilityhas been recorded as of December 31, 2014. Any liability imposed on ComEd or Generation for environmental matters relating to the generatingstations 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 MidwestGeneration listing such agreement in the January 2014 plan supplement as an agreement to be rejected in connection with the Plan. As discussedabove, the rejection became effective as part of the Plan. Subsequently, Generation increased its reserve by $15 million pursuant to the secondquarter 2014 actuarial study of such claims, of which an estimated $6 million pertains to Midwest Generation’s share. Midwest Generation publiclydisclosed 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 bodilyinjury claims under the contractual indemnity with ComEd. Exelon and Generation may be entitled to damages associated with the rejection of theagreement. These amounts are considered to be contingent gains and would not be recognized until realized. 435Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 inconnection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to anunaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. Inconnection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, theU.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additionallandfill cover. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediationalternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the finalsupplemental feasibility study to the U.S. EPA for review. In June 2012, the U.S. EPA requested that the PRPs perform additional analysis andgroundwater sampling as part of the supplemental feasibility study, and subsequently requested additional analysis sampling and modeling that willbe 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 thePRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additionalcover remedy; however, Generation believes the likelihood that the U.S. EPA would require a complete excavation remedy is remote. The currentestimated cost of the landfill cover remediation for the site is approximately $50 million, which will be allocated among all PRPs. Generation hasaccrued 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 sixadditional defendants. The complaint alleges that individuals living in the North St. Louis area within a three-mile radius of the West Lake Landfillsuffered damage to property or loss of use of property due to the defendants’ negligent handling of radioactive materials. On August 22, 2014, theplaintiffs 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 forcontamination 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. Theradioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s ManhattanProject. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium andmetals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. LattyAvenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized SitesRemedial 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. Basedon Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and hasestablished 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 and14 defendants, respectively, including Exelon, Generation and ComEd (the Exelon defendants) and Cotter. The suits allege that individuals livingin the North St. 436Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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, medicalmonitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filedvoluntary motions to dismiss the Exelon defendants from both lawsuits which were subsequently granted. Since May 30, 2012, several relatedlawsuits have been filed in the same court on behalf of various plaintiffs against Cotter and other defendants, but not Exelon. The allegations inthese related lawsuits mirror the initially filed lawsuits. In the event of a finding of liability, it is reasonably possible that Exelon would beconsidered liable due to its indemnification responsibilities of Cotter described above. On March 27, 2013, the U.S. District Court dismissed allstate common law actions brought under the initial two lawsuits; and also found that the plaintiffs had not properly brought the actions under thePrice-Anderson Act. On July 8, 2013, the plaintiffs filed amended complaints under the Price-Anderson Act. Cotter moved to dismiss the amendedcomplaints and has motions currently pending before the court. At this stage of the litigation, Exelon, Generation, and ComEd cannot estimate arange 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 PrioritiesList, 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 andentered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative SitesProgram. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site becameeffective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-upoptions. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and optionsprovided 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 allocatedamong 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 itspreferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs estimated rangeof costs noted above. Based on Generation’s preliminary review, it appears probable that Generation has liability and has established anappropriate accrual for its share of the estimated clean-up costs. A wholly owned subsidiary of Generation has agreed to indemnify BGE for mostof 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 theplacement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG). In 2008, CPSG investigatedand remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns andready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process toremediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $10 million, which hasbeen 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 inDundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and presentcleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup andinvestigation costs at the site. On March 11, 2013, BGE and three other PRP’s signed an Administrative Settlement Agreement and Order onConsent with the U.S. EPA which 437Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 andrecommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanupremedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE’s reasonably possibleloss, 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 combustionresiduals (CCR) from power plants, including the classification of CCR as non-hazardous waste under RCRA. The EPA ruling is effective 180 daysafter publication in the Federal Register, which is anticipated in early 2015. Under the regulation, CCR will continue to be regulated by most statessubject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coalash 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 anyremediation requirements that may be asserted for these former sites under the new federal regulations. For these reasons, Generation is unableto predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to formerly owned coal ashdisposal 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 certainfacilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscountedbasis 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 toGeneration, while the remaining $78 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actualexperience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to thereserve is necessary. During the second quarter of 2014, Generation increased its reserve by approximately $15 million, primarily due to increasedactual 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 anemployee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not apply topreclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the PennsylvaniaSuperior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was 438Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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-basedexposure to asbestos. Currently, Exelon, Generation and PECO are unable to predict whether and to what extent they may experience additionalclaims in the future as a result of this ruling; as such no increase to the asbestos-related bodily injury liability has been recorded as ofDecember 31, 2014. Increased claims activity resulting from this ruling could have a material adverse impact on Exelon, Generation’s and PECO’sfuture results of operations and cash flows. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. Theactions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestoshazard. 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 seekingseveral million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filedagainst BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have beendismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolvedfor 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. Giventhe limited discovery in these cases, BGE and Generation do not know the specific facts that are necessary to provide an estimate of thereasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts notknown 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 tradingactivities in and around the ISO-NY from September 2007 through December 2008. Prior to the Constellation merger, Constellation announced onMarch 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay, and has paid, a $135 million civilpenalty and $110 million in disgorgement. During the year ended December 31, 2012, Generation recorded expense of $195 million in Operating and maintenance expense within itsStatement of Operations and Comprehensive Income with the remaining $50 million recorded as a Constellation pre-acquisition contingency withinits Consolidated Balance Sheets. See Note 4—Mergers, Acquisitions, and Dispositions for additional information on the Constellation merger. 439Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 continuouspower interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damagessuffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingencyexpenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC awaiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events orconditions, 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 inconnection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000customers 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 damagecompensation 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 ICCheld 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 procedureestablished 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’sinfrastructure 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 andwinter storm dockets with the Illinois Appellate Court regarding the ICC’s interpretation of Section 16-125 of the Illinois Public Utilities Act. OnJuly 31, 2014, the Illinois Appellate Court reaffirmed the ICC’s decision in the appeal of the Summer 2011 Storm Docket and dismissed the appealof the February 2011 Blizzard Docket. The Illinois Appellate Court’s opinion has no accounting impact as ComEd previously established a liabilityin connection with the June 5, 2013 ICC ruling discussed below. ComEd has asked the Illinois Supreme Court to hear the matter. There is no settime 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 actualdamages 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 ofpotential losses given that no amount within the range represents a better estimate. ComEd’s ultimate liability will be based on actual claimseligible for reimbursement as well as the outcome of the appeal. Although reimbursements for actual damages will differ from the estimatedaccrual 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, ifany, cannot be reasonably estimated at this time, but may be material to ComEd’s results of operations and cash flows. 440Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 apresumptive class that would include all customers that ComEd enrolled in its Outage Alert text message program. The complaint alleges thatComEd violated the Telephone Consumer Protection Act (“TCPA”) by sending approximately 1.2 million text messages to customers without firstobtaining their consent to receive such messages. The complaint seeks certification of a class along with statutory damages, attorneys’ fees, andan order prohibiting ComEd from sending additional text messages. Such statutory damages could range from $ 500 to $ 1,500 per text. ComEdintends to contest the allegations of this suit. In February 2014, ComEd filed a motion to dismiss this class action complaint, which was denied inJune 2014. As of December 31, 2014, ComEd has a reserve, which is not material, representing its best estimate of probable loss associated withthis class action complaint. As ComEd is unable to predict the ultimate outcome of this proceeding, actual damages may differ from the estimatedamount 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 intercompanymoney 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 anydividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” isundefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to bepaid 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 ofcorporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does notbelieve these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meetExelon’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 sufficientto declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEdhas also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capitalstock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEdFinancing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an eventof 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 givingeffect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than theinvoluntary liquidating value of its then outstanding preferred securities. On May 1, 2013, PECO redeemed all outstanding preferred securities. Asa result, the above ratio calculation is no longer applicable. Additionally, PECO may not declare dividends on any shares of its capital stock in theevent that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. orPECO 441Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 trustsecurities 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 restrictionsestablished by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE isprohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculatedpursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit ratingagencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to deferinterest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) anydividends (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 withoutthe proper franchise rights from the City. BGE is currently reviewing the merits of this claim. BGE has not recorded an accrual for payment offranchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periodsmay 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. Theassessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a seriesof complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject toreasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) thedamages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In suchcases, 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 1999sale of fossil generating assets. 442Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ComprehensiveIncome 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 $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 $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 $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 andgross 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 (a) (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 — 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 (358) (358) — — — Total decommissioning-related activities 360 360 — — — Investment income 1 1 — (1) 7 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 — 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 (546) (546) — — — Total decommissioning-related activities 346 346 — — — Investment income 8 (1) — (1) 9 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(a)(b)(c)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 — 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 (530) (530) — — — Total decommissioning-related activities 325 325 — — — Investment income 20 3 1 2 11 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. SeeNote 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 endedDecember 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 135 135 — — — Nuclear fuel 1,073 1,073 — — — ARO accretion 345 345 — — — Total depreciation, amortization, accretion and depletion $3,868 $2,519 $687 $236 $371 445(a)(b)(c) (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 430 507 — — — Nuclear fuel 921 921 — — — ARO accretion 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 1,110 1,110 — — — Nuclear fuel 848 848 — — — ARO accretion 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 (a) (b) (c) (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 (132) (132) — — — Energy-related options 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 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 (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) 78 — 25 Fair value of net assets recorded upon CENG consolidation (3,400) (3,400) — — — Issuance of equity units 131 — — — — Nuclear fuel procurement 70 70 — — — Indemnification of like-kind exchange position — — 5 — — (a)Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investmentincome 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 nucleardecommissioning.(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. SeeNote 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 (a) (b) (c)(d)(e)(f)(g)(h)(i)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 (169) (169) — — — Energy-related options 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 (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 (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) (8) 13 (48) Consolidated VIE dividend to noncontrolling interest 63 63 — — — Indemnification of like-kind exchange position — — 176 — — (a)Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investmentincome 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 nucleardecommissioning.(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. SeeNote 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(a)(b)(c) (d) (e)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 (145) (145) — — — Energy-related options 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 141 32 — — 27 Severance costs 99 34 — — — Discrete impacts from EIMA (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 15 26 (4) Consolidated VIE dividend to noncontrolling interest 7,365 5,264 — — — (a)Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investmentincome 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 nucleardecommissioning.(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 moreinformation 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. SeeNote 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 capitalexpenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $5 millionrelated to PECO’s DOE SGIG programs. 449(a)(b)(c)(d)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofthe cash flow statement capital expenditures of $74 million, $27 million and $47 million, and reimbursements of $95 million, $37 million and $58million, 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 $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 85 27 — 23 4 Other investments 42 42 — — — Total investments $544 $104 $6 $31 $12 December 31, 2013 Exelon Generation ComEd PECO BGE Investments Equity method investments: Financing trusts $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 90 23 5 23 5 Other investments 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 ConsolidatedBalance 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 (a) (b)(c) (a) (b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 $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 92 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 $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 335 324 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 theMid-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, noseparate 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 incomeand 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 thefootprints of an ISO / RTO and/or NERC region. Descriptions of each of Generation’s six reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, WestVirginia, Delaware, the District of Columbia and parts of North Carolina. 451 (a)(b)(b) (a)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined Notes to Consolidated Financial Statements—(Continued)(Dollars in millions, except per share data unless otherwise noted) • Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky andTennessee, 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 ISO-NY, which covers the state of New York in its entirety. • ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas. • Other Regions not considered individually significant: • South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included withinMISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, NorthCarolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in theSPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi andArkansas. • 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 ofMISO. The CODMs for Exelon and Generation evaluate the performance of Generation’s power marketing activities and allocate resources basedon revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a usefulmeasurement of operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and maynot 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 costsinclude all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expenseincludes 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. CraneMaryland generating stations, and other miscellaneous revenues, unrealized mark-to-market impact of economic hedging activities, andamortization of certain intangible assets relating to commodity contracts recorded at fair value are also not allocated to a region. Exelon andGeneration do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of thesereportable segments. 452Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 financialstatements for the years ended December 31, 2014, 2013, and 2012 is as follows: Generation ComEd PECO BGE Other IntersegmentEliminations Exelon Operating revenues: 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: 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 : 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) ofunconsolidated 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 incometaxes: 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(a)(b)(c) (d) (e)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 endedDecember 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, andsales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation includerevenue 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 millionrelated to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended December 31, 2012, intersegment revenuesfor 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 Midwestregion, 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 forGeneration. 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 andexpenses 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 revenuesand 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 $86million, $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 betweenExelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amountsare 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 theactivity from CENG. 2014 2013 2012 Revenuesfromexternalcustomers Intersegmentrevenues TotalRevenues Revenuesfromexternalcustomers Intersegmentrevenues TotalRevenues Revenuesfromexternalcustomers Intersegmentrevenues TotalRevenues 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 1,319 (10) 1,309 946 22 968 755 78 833 Total Revenues forReportable Segments $14,249 $(6) $14,243 $13,610 $(1) $13,609 $13,656 $80 $13,736 Other 3,144 6 3,150 2,020 1 2,021 781 (80) 701 Total GenerationConsolidated OperatingRevenues $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 commoditycontracts 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 ofintersegment revenues. 454(a)(a)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 fromexternalcustomers IntersegmentRNF TotalRNF RNF fromexternalcustomers IntersegmentRNF TotalRNF RNF fromexternalcustomers IntersegmentRNF TotalRNF 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 611 (284) 327 334 (133) 201 53 78 131 Total Revenues net ofpurchased power and fuelexpense for ReportableSegments $8,119 $(630) $7,489 $7,027 $(353) $6,674 $7,159 $80 $7,239 Other (651) 630 (21) 406 353 759 217 (80) 137 Total Generation Revenues netof purchased power and fuelexpense $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 commoditycontracts 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 ofintersegment revenue net of purchased power and fuel expense. 455(a)(a)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 EndedDecember 31, 2014 2013 2012 Operating revenues from affiliates: PECO $1 $10 $6 CENG 17 56 42 BGE 5 4 — Total operating revenues from affiliates $23 $70 $48 Purchase power and fuel from affiliates: CENG $282 $992 $793 Keystone Fuels, LLC 138 144 119 Conemaugh Fuels, LLC 99 98 101 Safe Harbor Water Power Corp 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 16 16 12 Total interest expense to affiliates, net $41 $41 $37 Earnings (losses) in equity method investments: CENG $(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 $— $3 Payables to affiliates (current): CENG $— $85 ComEd Financing III 4 4 PECO Trust III 1 1 BGE Capital Trust II 3 4 Keystone Fuels, LLC — 12 Conemaugh Fuels, LLC — 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(a)(b)(a) (c)(d)(d)(d)(f)(e)(b)(c)(d)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 ofintersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement ofOperations. 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 thepermanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management andbilling 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 aNuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporateand 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 inCENG, 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 itpurchased 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 asubsidiary 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 areeliminated 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 andfuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, andDispositions 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 aresult of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment inCENG, 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 ofExelon’s merger with Constellation on March 12, 2012. 457Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 EndedDecember 31, 2014 2013 2012 Operating revenues from affiliates: ComEd $176 $506 $795 PECO 198 405 543 BGE 387 455 322 CENG 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 282 992 793 Keystone Fuels, LLC 138 144 119 Conemaugh Fuels, LLC 99 98 101 Safe Harbor Water Power Corporation 12 22 23 Total purchase power and fuel from affiliates $557 $1,270 $1,044 Operating and maintenance from affiliates: ComEd $3 $2 $2 PECO 2 1 3 BSC 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 $(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(a)(b)(c)(d)(e)(i)(i) (i) (f) (f) (g) (h)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 $— $3 ComEd 43 38 PECO 29 38 BGE 40 27 Other 1 2 Total receivables from affiliates (current) $113 $108 Long-term debt due to affiliates (current): Exelon Corporate 556 — Payables to affiliates (current): CENG $— $85 Exelon Corporate 12 7 BSC 83 66 ComEd 12 — Keystone Fuels, LLC — 12 Conemaugh Fuels, LLC — 9 Other — 2 Total payables to affiliates (current) $107 $181 Long-term debt due to affiliates (noncurrent): Exelon Corporate 943 1,523 Payables to affiliates (noncurrent): BSC $1 $— ComEd 2,389 2,293 PECO 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—RegulatoryMatters 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-yearagreements 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 foradditional information.(d)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 thepermanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management andbilling 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 aNuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporateand 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 inCENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.(e)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 itpurchased 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 asubsidiary 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 areeliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.(f)Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distributionand transmission services from ComEd for the delivery of electricity to its generating stations. 459(d)(a)(b)(c)(l)(e)(j)(g)(i)(i)(l)(g)(k)(k)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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. Allservices 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 ofpurchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, seeNote 5—Investment in Constellation Energy Nuclear Group, LLC.(i)During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power andfuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, andDispositions for more information.(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 processedon 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 theunderlying 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—AssetRetirement 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) assumedintercompany 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 Debtto affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s ConsolidatedBalance Sheets. 460Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 EndedDecember 31, 2014 2013 2012 Operating revenues from affiliates Generation $4 $3 $2 Purchased power from affiliate Generation $176 $512 $789 Operating and maintenance from affiliate BSC $166 $157 $163 Interest expense to affiliates, net: ComEd Financing III $13 $13 $13 Capitalized costs BSC $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 $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 $2,389 $2,293 Exelon Corporate 182 176 Total receivable from affiliates (noncurrent) $2,571 $2,469 Payables to affiliates (current): Generation $43 $38 BSC 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. Allservices are provided at cost, including applicable overhead. A portion of such services is capitalized. 461 (a) (b) (b) (c) (d) (e)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 activewelfare 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 expenseincurred 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 theextent 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 toComEd’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 EndedDecember 31, 2014 2013 2012 Operating revenues from affiliates: Generation $2 $1 $3 Purchased power from affiliate Generation $194 $392 $533 Operating and maintenance from affiliates: BSC $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 $39 $46 $54 Cash dividends paid to parent $320 $332 $343 Contribution from parent $24 $27 $9 462(a) (b)(c) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 $3 $3 Receivable from affiliate (current): ComEd $2 $— BGE 1 3 Total receivable from affiliates (current) $3 $3 Receivable from affiliate (noncurrent): Generation $490 $447 Payables to affiliates (current): Generation $29 $38 BSC 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-yearagreements 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 servicesare 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 theactive 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 claimexpense 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 withdecommissioning 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 (d)(e) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 EndedDecember 31, 2014 2013 2012 Operating revenues from affiliates: Generation $25 $13 $10 Purchased power from affiliate Generation $382 $452 $396 Operating and maintenance from affiliates: BSC $103 $83 $106 Interest expense to affiliates, net: BGE Capital Trust II $16 $16 $16 Capitalized costs BSC $19 $15 $21 Contribution from parent $— $— $66 December 31, 2014 2013 Prepaid voluntary employee beneficiary association trust $1 $1 Payables to affiliates (current): Generation $40 $27 BSC 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 servicesare 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 activewelfare 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 expenseincurred by the plans over time. The prepayment is included in other current assets. 464 (a) (b) (c) (c) (d)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 thatExelon considers necessary for a fair presentation of such amounts: Operating Revenues Operating Income Net (Loss) Incomeon CommonStock 2014 2013 2014 2013 2014 2013 Quarter ended: March 31 $7,237 $6,082 $168 $513 $90 $(4) June 30 6,024 6,141 842 1,005 522 490 September 30 6,912 6,502 1,739 1,262 993 738 December 31 7,255 6,163 348 889 18 495 (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’sConsolidated 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 Statementsof 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 theCombined 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 ofLong-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. Average Basic SharesOutstanding(in millions) Net (Loss) Incomeper 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 SharesOutstanding(in millions) Net (Loss) Incomeper 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(a)(b)(c)(a)(a)(b)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 sharebasis: 2014 2013 FourthQuarter ThirdQuarter SecondQuarter FirstQuarter FourthQuarter ThirdQuarter SecondQuarter FirstQuarter 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) Incomeon MembershipInterest 2014 2013 2014 2013 2014 2013 Quarter ended: March 31 $4,390 $3,533 $(384) $(59) $(185) $(18) June 30 3,789 4,070 441 603 340 330 September 30 4,412 4,255 1,225 729 771 490 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 inGeneration’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’sConsolidated 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 1,080 259 232 111 96 September 30 1,222 1,156 288 278 126 126 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 Operationsand Comprehensive Income. The reclassifications did not affect ComEd’s Net (Loss) Income. 466(a)(a)(b)(a)(a)(b)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCombined 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 Incomeon CommonStock 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 Incomeattributable toCommon 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 467Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 reportingof information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by eachregistrant to ensure that (a) information relating to that registrant, including its consolidated subsidiaries, that is required to be included in filingsunder the Securities Exchange Act of 1934, is accumulated and made known to that registrant’s management, including its principal executiveofficer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regardingrequired disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periodsspecified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherentlimitations 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 financialreporting of a recently acquired business may be omitted from management’s evaluation of disclosure controls and procedures, management isexcluding an assessment of such internal controls of Integrys, which we acquired on November 1, 2014, from its evaluation of the effectiveness ofExelon’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 financialstatement 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 suchregistrant’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 tomaintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting thatoccurred 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. Asa result of that assessment, management determined that there were no material weaknesses as of December 31, 2014 and, therefore, concludedthat each registrant’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting isincluded in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. 468Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 9B.OTHER INFORMATION Exelon, Generation and ComEd None. PECO and BGE None. 469Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART III Exelon Generation Company, LLC, Baltimore Gas and Electric Company, and PECO Energy Company meet the conditions set forth inGeneral 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 theRegistrants 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 beneficialreporting 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 beforeApril 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 FinancialOfficer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and isavailable on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to anyshareholder who requests such document from Bruce G. Wilson, Senior Vice President, Deputy General Counsel, and Corporate Secretary, ExelonCorporation, 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 aprovision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose thenature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K. 470Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 11.EXECUTIVE COMPENSATION The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the2015 Exelon Proxy Statement or the ComEd 2015 Information Statement and incorporated herein by reference. 471Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 theComEd 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 tobe issued uponexercise of outstandingOptions, warrants andrights (Note 1) Weighted-averageprice of outstandingOptions,warrantsand rights(Note 2) Number of securitiesremaining availablefor future issuanceunder equitycompensation plans(excludingsecuritiesreflected incolumn [B]) (Note 3) Equity compensation plans approved by securityholders 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 andshares 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 performanceshares and performance share transition awards granted in 2013 and 2014, the total includes the maximum number of shares that could be granted, if performance, totalshareholder 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 suchawards 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 theExelon 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 legacyConstellation 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 subsidiarycompanies. 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 ofoutstanding 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. 472Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 2015Exelon Proxy Statement or the ComEd 2015 Information Statement and incorporated herein by reference. 473Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsITEM 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 IndependentAccountant for 2015 in the 2015 Proxy Statement and the 2015 ComEd Information Statement and incorporated herein by reference. 474Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPART 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 Statements2. Financial Statement Schedules: Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2014 and 2013 and for the Years EndedDecember 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 informationis provided in the consolidated financial statements, including the notes thereto. 475Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Statements of Operations and Other Comprehensive Income For the Years EndedDecember 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 476Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon Corporation and Subsidiary Companies Schedule I – Condensed Financial Information of Parent (Exelon Corporate) Condensed Statements of Cash Flows For the Years EndedDecember 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 477Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 478Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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, 2014and 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 479Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 condensedfinancial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statementsshould 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’spreferred stock. Exelon owned none of PECO’s preference securities, which PECO redeemed in 2013. 2. Mergers On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restatedas of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelonname and be headquartered in Chicago. Exelon and PHI continue to expect to complete the merger in the second or third quarter of 2015. SeeNote 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on theMerger Agreement with PHI. On March 12, 2012, Exelon Corporation completed the merger contemplated by the Merger Agreement, among Exelon, Bolt AcquisitionCorporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged intoConstellation (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 intoExelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’sinterest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly ownedsubsidiary 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 fromConstellation 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’sassets acquired and liabilities assumed is recorded as a regulatory asset at Exelon Corporate as Exelon did not apply push-down accounting toBGE. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional informationon the merger with Constellation. Also see Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statementsfor additional information on BGE’s push-down accounting treatment. 480Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 nocommercial 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 bankcommitments of $500 million through May 2019. As of December 31, 2014, Exelon Corporation had available capacity under those commitmentsof $494 million. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further informationregarding 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: MaturityDate December 31, Rates 2014 2013 Long-term debt Junior subordinated notes 6.5% 2017 $1,150 $— Senior unsecured notes 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(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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’scommitments 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 EndedDecember 31, (In millions) 2014 2013 2012 Operating and maintenance from affiliates: Business Services Company, LLC $38 $34 $72 Interest income from affiliates, net: Exelon Generation Consolidated $53 $36 $75 Equity in earnings of investments: Exelon Energy Delivery Company, LLC $958 $834 $713 Exelon Ventures Company, LLC 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 — — (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 (a)(b)(c) (d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 $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 $262 $179 Exelon Generation Consolidated $556 $— Total receivable from affiliates (current): $818 $179 Investments in affiliates: Business Services Company, LLC $193 $201 Exelon Energy Delivery Company, LLC 13,590 12,956 Exelon Ventures Company, LLC — 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 $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, andExelon 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 Generationfor 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) assumedintercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-TermDebt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’sConsolidated Balance Sheets. 483(a) (a)(e) (a) (b) (c)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 atBeginningof Period Charged toCosts andExpenses Chargedto OtherAccounts Deductions Balance atEndof Period (in millions) For the year ended December 31, 2014 Allowance for uncollectible accounts $272 $175 $69 $205 $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 $293 $121 $37 $179 $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 $199 $144 $136 $186 $293 Deferred tax valuation allowance 10 18 18 10 36 Reserve for obsolete materials 60 2 2 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 endedDecember 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(a)(c)(d)(a)(c)(d) (a)(b)(c)(d)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 Statements2. 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 informationis provided in the consolidated financial statements, including the notes thereto 485Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExelon 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 atBeginningof Period Charged toCosts andExpenses Chargedto OtherAccounts Deductions Balance atEndof 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 $11 $84 Deferred tax valuation allowance — 17 18 — 35 Reserve for obsolete materials 59 — 2 11 50 (a)Represents the addition of Constellation’s results as of March 12, 2012, the date of the merger. 486(a)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCommonwealth Edison Company and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts ComEd1. 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 Statements2. 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 informationis provided in the consolidated financial statements, including the notes thereto 487Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCommonwealth 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 atBeginningof Period Charged toCosts andExpenses Chargedto OtherAccounts Deductions Balance atEndof Period (in millions) For the year ended December 31, 2014 Allowance for uncollectible accounts $62 $45 $33 $56 $84 Reserve for obsolete materials 2 — 2 2 2 For the year ended December 31, 2013 Allowance for uncollectible accounts $70 $33 $29 $70 $62 Reserve for obsolete materials 2 1 — 1 2 For the year ended December 31, 2012 Allowance for uncollectible accounts $78 $42 $26 $76 $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(a)(b)(a)(b)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO Energy Company and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts PECO1. 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 Statements2. 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 informationis provided in the consolidated financial statements, including the notes thereto 489Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPECO 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 atBeginningof Period Charged toCosts andExpenses Chargedto OtherAccounts Deductions Balance atEndof Period (in millions) For the year ended December 31, 2014 Allowance for uncollectible accounts $107 $52 $11 $70 $100 Reserve for obsolete materials 1 — — — 1 For the year ended December 31, 2013 Allowance for uncollectible accounts $99 $61 $7 $60 $107 Reserve for obsolete materials 1 — — — 1 For the year ended December 31, 2012 Allowance for uncollectible accounts $92 $60 $8 $61 $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 endedDecember 31, 2014, 2013, and 2012, respectively.(b)Primarily charges for late payments.(c)Write-off of individual accounts receivable. 490 (a)(b)(c) (a)(b)(c) (a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBaltimore Gas and Electric Company and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts BGE1. 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 Statements2. 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 informationis provided in the consolidated financial statements, including the notes thereto 491Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsBaltimore 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 atBeginningof Period Charged toCosts andExpenses Chargedto OtherAccounts Deductions Balance atEndof Period (in millions) For the year ended December 31, 2014 Allowance for uncollectible accounts $46 $64 $17 $60 $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 $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 $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(b)(a)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibits 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, asamended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do notauthorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basisand the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request. Exhibit No. Description2-1 Agreement and Plan of Merger dated as of April 28, 2011 by and among Exelon Corporation, Bolt Acquisition Corporation andConstellation 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 EnergyGroup, 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 EnergyDelivery 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 andExelon 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 RavenPower 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 EnergyGroup, 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 asExhibit 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 andElectric 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 andElectric Company Utility), Inc. (Designated as Exhibit No. 99.3 to the Current Report on Form 8-K dated February 4, 2010, filedby 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 PurpleAcquisition Corp. (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit 2.1). 493Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description 2-10-2 Amended and Restated Agreement and Plan of Merger, dated as of July 18, 2014, among Pepco Holdings, Inc., Exelon Corporationand 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 betweenPepco 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-Qfor 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 ofResolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preferencestock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 CumulativePreference 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 asExhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, filed by Baltimore Gas and ElectricCompany, 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 GSSHoldings (BGE Utility), Inc. (Designated as Exhibit No. 99.1 to the Current Report on Form 8-K dated February 4, 2010, filed byBaltimore 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 EnergyCompany) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (RegistrationNo. 2-2281, Exhibit B-1). 494Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit 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 September25, 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 September17, 2012 4.1 September 15, 2013 000-16844, Form 8-K dated September23, 2013 4.1 September 15, 2013 000-16844, Form 8-K datedSeptember 23, 2013 4.1 September 1, 2014 000-16169, Form 8-K dated September15, 2014 4.14-2 Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-183751, Form S-3, Prospectus). 495Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description 4-3 Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company ofIllinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture theretodated 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 datedJanuary 22, 2003 4-4 March 14, 2003 1-1839, Form 8-K datedApril 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 496Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit 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 September7, 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 November10, 2014 4.1 4-3-2 Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage ofCommonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (FileNo. 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 NationalAssociation, 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). 497Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit 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, Exhibit4.1). 4-11 Form of 6.000% Senior Secured Notes due 2033 issued by Exelon Generation Company, LLC (File No. 333-85496, Form 8-Kdated 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 andCharles 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, NationalAssociation, 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, Form8-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 (File333-85496, 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. (Designatedas 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 January24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, filed byConstellation 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, astrustee. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, filed by ConstellationEnergy Group, Inc., File No. 333-135991). 498Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit 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 byConstellation 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, astrustee. (Designated as Exhibit No. 4(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed byConstellation 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 CurrentReport on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to theCurrent 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 BankTrust Company Americas, as trustee (including form of Baltimore Gas and Electric Company Officer’s Certificate and form ofSenior Secured Bond) (Designated as Exhibit Nos. 4(u) and 4(u)(1) to Post-Effective Amendment No. 1 to the RegistrationStatement 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 ConstellationEnergy 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 ExhibitNo. 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 and1-1910).4-32 Baltimore Gas and Electric Company Deed of Easement and Right-of-Way Grant dated as of July 9, 2009 (Designated as ExhibitNo. 4(u)(2) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, filed byConstellation 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 Trusteeand Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, filed by BaltimoreGas 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 CompanyAmericas, as Trustee and Securities Intermediary (Designated as Exhibit No. 4(b) to the Quarterly Report on Form 10-Q for thequarter ended September 30, 2009, filed by Baltimore Gas and Electric Company, File No. 1 1910). 499Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit 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 June30, 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 asof 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 EnergyGroup, Inc., with the form of Notes attached thereto. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K datedDecember 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 ElectricCompany, with the form of Notes attached thereto. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K datedNovember 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., asTrustee. (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 TrustCompany, 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 datedJune 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 (FileNo. 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, WolfHollow I Power, LLC, Colorado Bend I Power, LLC, Laporte Power, LLC, Handley Power, LLC and Mountain Creek Power, LLC, thelenders 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. 500Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description 10-5 Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001Form 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 Form10-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 effectiveJanuary 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 Form10-K, Exhibit 10.24).10-17 Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective July 1, 2013. (File No. 1-16169, Schedule14A 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-Kfiled 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 RestatedEffective 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, StamfordBranch (File No. 333-85496, Form 8-K dated February 22, 2011, Exhibit No. 10-1). 501Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit 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 Form10-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 January28, 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, 2006Form 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 Form10-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 VariousFinancial 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 FinancialInstitutions (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 financialinstitutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form8-K dated August 10, 2013, Exhibit No. 99-1). 502Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description 10-41 Amendment No. 1 to Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, as Borrower, thevarious 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 ExhibitNo. 10(b) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation EnergyGroup, 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 byConstellation 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 asExhibit No. 10(b) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed by ConstellationEnergy 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 theConstellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., FileNos. 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 ExhibitNo. 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) tothe 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) tothe 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 asExhibit 10(a) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed by ConstellationEnergy Group, Inc., File Nos. 1-12869 and 1-1910). 503Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description 10-53 Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated. * (Designated as Exhibit10(d) to the Constellation Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed by Constellation EnergyGroup, 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 theCurrent 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 Form10-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 Gasand Electric Company, as servicer (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated July 5, 2007, filed byBaltimore 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 ElectricCompany, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated July 5, 2007, filed by BaltimoreGas 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 EnergyNuclear 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-Kdated 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, byand 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, byand 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, filedby 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, byand 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 byConstellation 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-Kdated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). 504Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description 10-63 Settlement Agreement between EDF Inc., Exelon Corporation, Exelon Energy Delivery Company, LLC, Constellation EnergyGroup, Inc. and Baltimore Gas and Electric Company dated January 16, 2012. (Designated as Exhibit No. 10.1 to the CurrentReport 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 datedApril 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 financialinstitutions named therein, as Lenders, and Barclays Bank PLC, as Administrative Agent (File No. 001-16169, Form 8-K datedApril 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 institutionssignatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K datedJune 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 financialinstitutions 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 financialinstitutions 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, thefinancial 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 Chargesand Preference Stock Dividends. 505Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit 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). Subsidiaries21-1 Exelon Corporation21-2 Exelon Generation Company, LLC21-3 Commonwealth Edison Company21-4 PECO Energy Company21-5 Baltimore Gas and Electric Company Consent of Independent Registered Public Accountants23-1 Exelon Corporation23-2 Exelon Generation Company, LLC23-3 Commonwealth Edison Company23-4 PECO Energy Company23-5 Baltimore Gas and Electric Company Power of Attorney (Exelon Corporation)24-1 Anthony K. Anderson24-2 Ann C. Berzin24-3 John A. Canning, Jr.24-4 Christopher M. Crane24-5 Yves C. de Balmann24-6 Nicholas DeBenedictis24-7 Paul L. Joskow24-8 Reserved.24-9 Robert J. Lawless24-10 Richard W. Mies24-11 William C. Richardson24-12 John W. Rogers, Jr.24-13 Mayo A. Shattuck III24-14 Stephen D. Steinour Power of Attorney (Commonwealth Edison Company)24-15 James W. Compton24-16 Christopher M. Crane24-17 A. Steven Crown24-18 Nicholas DeBenedictis24-19 Peter V. Fazio, Jr.24-20 Michael Moskow24-21 Denis O’Brien24-22 Anne R. Pramaggiore24-23 Reserved. 506Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description Power of Attorney (PECO Energy Company)24-24 Craig L. Adams24-25 Christopher M. Crane24-26 M. Walter D’Alessio24-27 Nicholas DeBenedictis24-28 Reserved.24-29 Reserved.24-30 Denis O’Brien24-31 Ronald Rubin Power of Attorney (Baltimore Gas and Electric Company)24-32 Ann C. Berzin24-33 Christopher M. Crane24-34 Michael E. Cryor24-35 James R. Curtiss24-36 Calvin G. Butler, Jr.24-37 Joseph Haskins, Jr.24-38 Carla D. Hayden24-39 Denis O’Brien24-40 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 onForm 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 Corporation31-2 Filed by Jonathan W. Thayer for Exelon Corporation31-3 Filed by Kenneth W. Cornew for Exelon Generation Company, LLC31-4 Filed by Bryan P. Wright for Exelon Generation Company, LLC31-5 Filed by Anne R. Pramaggiore for Commonwealth Edison Company31-6 Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company31-7 Filed by Craig L. Adams for PECO Energy Company31-8 Filed by Phillip S. Barnett for PECO Energy Company31-9 Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company31-10 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 forthe year ended December 31, 2013 filed by the following officers for the following registrants:32-1 Filed by Christopher M. Crane for Exelon Corporation32-2 Filed by Jonathan W. Thayer for Exelon Corporation32-3 Filed by Kenneth W. Cornew for Exelon Generation Company, LLC32-4 Filed by Bryan P. Wright for Exelon Generation Company, LLC 507Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsExhibit No. Description32-5 Filed by Anne R. Pramaggiore for Commonwealth Edison Company32-6 Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company32-7 Filed by Craig L. Adams for PECO Energy Company32-8 Filed by Phillip S. Barnett for PECO Energy Company32-9 Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company32-10 Filed by David M. Vahos Baltimore Gas and Electric Company101.INS XBRL Instance101.SCH XBRL Taxonomy Extension Schema101.CAL XBRL Taxonomy Extension Calculation101.DEF XBRL Taxonomy Extension Definition101.LAB XBRL Taxonomy Extension Labels101.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. 508Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSIGNATURES 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 besigned 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 CORPORATIONBy: /S/ CHRISTOPHER M. CRANE Name: Christopher M. CraneTitle: 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 theregistrant 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 (PrincipalAccounting Officer) This annual report has also been signed below by Darryl M. Bradford, Attorney-in-Fact, on behalf of the following Directors on the dateindicated: Anthony K. AndersonAnn C. BerzinJohn A. Canning, Jr.Yves C. de BalmannNicholas DeBenedictis Paul L. JoskowRobert J. LawlessRichard W. MiesWilliam C. RichardsonJohn W. Rogers, Jr.Mayo A. Shattuck IIIStephen D. Steinour By: /S/ DARRYL M. BRADFORD February 13, 2015Name: Darryl M. Bradford 509Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSIGNATURES 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 besigned on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 13th day of February, 2015. EXELON GENERATION COMPANY, LLCBy: /S/ KENNETH W. CORNEW Name: Kenneth W. CornewTitle: 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 theregistrant and in the capacities indicated on the 13th day of February, 2015. 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 FinancialOfficer)/S/ ROBERT M. AIKEN Robert M. Aiken Chief Accounting Officer (Principal Accounting Officer) 510Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSIGNATURES 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 besigned on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 13th day of February, 2015. COMMONWEALTH EDISON COMPANYBy: /S/ ANNE R. PRAMAGGIORE Name: Anne R. PramaggioreTitle: 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 theregistrant and in the capacities indicated on the 13th day of February, 2015. 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 dateindicated: James W. ComptonA. Steven CrownNicholas DeBenedictisPeter V. Fazio, Jr. Michael MoskowDenis P. O’Brien By: /S/ ANNE R. PRAMAGGIORE February 13, 2015Name: Anne R. Pramaggiore 511Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSIGNATURES 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 besigned on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 13th day of February, 2015. PECO ENERGY COMPANYBy: /S/ CRAIG L. ADAMS Name: Craig L. AdamsTitle: Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of theregistrant and in the capacities indicated on the 13th day of February, 2015. 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 dateindicated: M. Walter D’Alessio Denis P. O’BrienNicholas DeBenedictis Ronald Rubin By: /S/ CRAIG L. ADAMS February 13, 2015Name: Craig L. Adams 512Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSIGNATURES 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 besigned on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 13th day of February, 2015. BALTIMORE GAS AND ELECTRIC COMPANYBy: /S/ CALVIN G. BUTLER, JR. Name: Calvin G. Butler, Jr.Title: 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 theregistrant and in the capacities indicated on the 13th day of February, 2015. 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 (PrincipalFinancial 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 dateindicated: Ann C. Berzin Joseph Haskins, Jr.Michael E. Cryor Carla D. HaydenJames R. Curtiss Denis O’BrienMichael D. Sullivan By: /S/ CALVIN G. BUTLER, JR. February 13, 2015Name: Calvin G. Butler, Jr. 513Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 10.3Exelon CorporationUnfunded Deferred Compensation Plan for Directors(Amended and Restated Effective March 12, 2012)The purpose of this Unfunded Deferred Compensation Plan for Directors (the “Plan”) is to permit Directors of Exelon Corporation (“Exelon”) toelect to defer receipt of directors’ fees. The Plan as set forth herein is an amendment and restatement of the Plan as originally adopted effective October 20,2000 and previously amended and restated as of January 1, 2009 and January 1, 2011, and is a successor to the PECO Energy Company Unfunded DeferredCompensation Plan for Directors (the “Prior Plan”).1. Administration. The Plan shall be administered by the Corporate Secretary of Exelon or his or her designee (the “Secretary”), or such otherindividual or individuals as designated by the Board of Directors of Exelon (the “Exelon Board”). The Secretary shall interpret the Plan and establish suchrules and regulations of plan administration that he or she deems appropriate. The cost of plan administration shall be paid by Exelon and its participatingsubsidiaries, and shall not be charged against the deferred accounts of Plan participants.2. Eligibility. All Directors of Exelon (other than full-time employees of Exelon or its subsidiaries) shall be eligible to participate in the Plan.Effective as of January 1, 2011, all Directors of Commonwealth Edison Company (“ComEd”) and PECO Energy Company (“PECO”) who are not full-timeemployees of Exelon or its subsidiaries shall also be eligible to participate in the Plan. In addition, effective as of March 12, 2012, all Directors of BaltimoreGas and Electric Company (“BGE”) who are not full-time employees of Exelon or its subsidiaries shall also be eligible to participate in the Plan.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.3. Deferrals. (a) Prior to the first day of each calendar year, each eligible Director may elect in writing to defer the receipt of all or a portion of hisor her directors’ fees earned with respect to his or her service on the board of directors of Exelon, ComEd, PECO and/or BGE (each such board of directors, a“Board”) for such calendar year, by filing a written Director’s deferral agreement form with the Secretary with respect to each such Board on which theDirector serves. A Director who first becomes eligible to participate in the Plan after the first day of any calendar year shall be permitted to make the electiondescribed in this Section 3 not later than 30 days after becoming eligible to participate in the Plan, and such election shall apply only to directors’ feesearned during the remainder of such calendar year. In all events, each deferral election made under this Plan shall apply only to fees earned after the date ofsuch election. Deferred amounts under the Plan, together with deferred amounts and attributable earnings under the Prior Plan, shall be credited to a deferralaccount in the participant’s name (“Deferral Account”) for later distribution. Each participant’s Deferral Account shall be a bookkeeping entry only, and noneof Exelon, ComEd, PECO or BGE shall be required to fund the Deferral Account. Any assets that may be held to fund a Deferral Account shall at all timesremain unrestricted assets of Exelon, ComEd, PECO or BGE in its corporate capacity and not as a fiduciary, and shall be subject to the claims of its generalcreditors. Pending distribution, each participant’s Deferral Account shall be credited with earnings or interest as provided in Section 3(b).(b) (1) For purposes of measuring the earnings or losses credited to a participant’s Deferral Account, the participant may select, fromamong the investment funds available from time to time under the Exelon Corporation Employee Savings Plan (the “Savings Plan”), the investment funds inwhich all or part of his or her Deferral Account shall be deemed to be invested. -2-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(2) The participant shall make an investment designation in the form and manner prescribed by the Secretary, which shall remaineffective until another valid designation has been made by the participant as herein provided. The Secretary may, but need not, permit separate investmentdesignations with respect to amounts attributable to fees earned with respect to service on each Board. The participant may amend his or her investmentdesignation at such times and in such manner as prescribed by the Secretary. A timely change to the participant’s investment designation shall becomeeffective as soon as administratively practicable after such designation is submitted.(3) The investment funds deemed to be made available to the participant, and any limitation on the maximum or minimumpercentages of the participant’s Deferral Account that may be deemed to be invested in any particular fund, shall be the same as available or in effect fromtime to time under the Savings Plan.(4) Except as provided below, the participant’s Deferral Account shall be deemed to be invested in accordance with his or herinvestment designations, and the Deferral Account shall be credited with earnings (or losses) as if invested as directed by the participant.To the extent that the participant does not furnish complete investment instructions, then the Deferral Account shall be deemed investedin the default investment fund then in effect under the Savings Plan. The Deferral Accounts maintained pursuant to the Plan are for bookkeeping purposesonly and Exelon is under no obligation to invest such amounts.Exelon shall provide a statement to each participant not less frequently than annually showing such information as is appropriate,including the aggregate amount in his or her Deferral Account, as of a reasonably current date.4. Distributions. (a) The amount credited to a participant’s Deferral Account with respect to his or her participation on each Board shall bedistributed to the participant in, or beginning in, April of the first year beginning after the occurrence of one of the following -3-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.distribution events, as the participant shall direct in his or her Benefit Distribution Election Form: (i) the participant’s separation from service, within themeaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), as a Director of Exelon, ComEd, PECO, BGE and their affiliates,(ii) the participant’s 65th birthday or (iii) the participant’s 72nd birthday. Distributions shall be paid in a lump sum payment or in annual installments over aperiod of up to 10 years, as the participant shall direct in his or her Benefit Distribution Election Form. Each installment payment shall be determined bymultiplying the balance remaining to the credit of the Deferral Account as of March 31 of such year (including earnings or interest credited under Section 3)by a fraction, the numerator of which is “1” and the denominator of which is the number of years (including the current year) for which payments are yet to bemade. Any unpaid balance in the Deferral Account shall be credited with earnings or interest as provided in Section 3. In the event a Director who has electeda distribution event based on his or her 65th or 72nd birthday continues to serve as a Director after the date such distributions commence, then in the yearprior to the year in which such distributions commence such Director shall file a new Benefit Distribution Election Form governing any amounts credited tohis or her Deferral Account after the date such distributions commence. If the Director does not file such new Benefit Distribution Election Form, then theDirector shall be deemed to have elected to receive a lump sum distribution of any such amounts upon the Director’s separation from service.(b) Except as permitted under Section 4(c) or 4(d), each Director must submit a Benefit Distribution Election Form for amountsattributable to fees earned with respect to service on a Board at the time such Director makes his or her initial deferral election under the Plan with respect tohis or her service on such Board (provided that a Director who participated in the Plan prior to January 1, 2009 and had not commenced distributions musthave submitted such form not later than December 31, 2008). If a Director does not submit a Benefit Distribution Election Form -4-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.during this period, then such Director shall be deemed to have elected to receive the portion of his or her Account attributable to fees earned for service onsuch Board in the form of installments payments over a period of ten years upon the Director’s separation from service.(c) Notwithstanding Sections 4(a) and 4(b), each participant who had not commenced and was not scheduled to commence the receipt ofdistributions under the Plan on or before December 31, 2007 was permitted to submit a Benefit Distribution Election Form on or before June 30, 2007 whichprovided for the payment of such participant’s Deferral Account (i) at any of the times and in any of the forms permitted under Section 4(a) of the Plan or(ii) in a lump sum payment in the first quarter of 2008; provided that such election did not cause any payment to be made in 2007 and did not apply to anypayment that otherwise would be paid in 2007. This special election right was intended to comply with the transition rule set forth in IRS Notice 2005-1,Q&A-19(c), and extended in the preamble to regulations proposed under Section 409A of the Code and IRS Notice 2006-79, which permits participants indeferred compensation plans to change the date on which deferred compensation is payable.(d) A Director may elect to change the time and/or method of his or her distributions payable under the Plan in accordance withprocedures prescribed by the Secretary; provided that, in accordance with Section 409A of the Code, any such change in a distribution election (i) shall notbe effective until 12 months after it is submitted to the Secretary, (ii) must be submitted to the Secretary at least 12 months prior to the date on which suchdistributions were previously scheduled to commence and (iii) must provide for distributions to commence at least five years after the date on which suchdistributions were previously scheduled to commence. No more than one such election change shall be permissible with respect to the portion of a Director’saccount attributable to service with any Board. -5-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.5. Death Benefits. Each participant shall designate a beneficiary or beneficiaries to receive any remaining amounts payable from his or herDeferral Account after the participant’s death. The beneficiaries, and any priority or allocation between them, shall be designated in the manner specified bythe Secretary. If a participant dies before the entire balance in his or her Deferral Account has been paid out, the remaining balance shall be paid to thebeneficiary in a lump sum upon the participant’s death. If the participant is not survived by a designated beneficiary, the participant’s beneficiary shall be theparticipant’s spouse, if living, or otherwise, the participant’s estate. If a beneficiary survives the participant but dies before the entire balance payable to himor her has been distributed, any remaining balance shall be paid to the beneficiary’s estate in a lump sum. In the absence of contrary proof, the participantshall be deemed to have survived any designated beneficiary. A participant may change his or her beneficiary designation under this Section at any timeuntil his or her death by filing a written beneficiary designation with the Secretary, in the manner specified by the Secretary.6. Unforeseeable Financial Emergency. The Secretary may, in his or her discretion, direct that a participant be paid an amount in cash (not inexcess of the balance of his or her Deferral Account) sufficient to meet an unforeseeable emergency. An “unforeseeable emergency” means (i) a severefinancial hardship to a Director resulting from an illness or accident of the Director, or the spouse or a dependent (as defined in Section 152(a) of the Code) ofthe Director, (ii) the loss of a Director’s property due to casualty or (iii) such other similar extraordinary and unforeseeable circumstances arising as a result ofevents beyond the control of the Director, within the meaning of Section 409A of the Code. A Director’s written request for such a payment shall describe thecircumstances which the Director believes justify the payment and an estimate of the amount necessary to eliminate the unforeseeable emergency. Animmediate payment to satisfy an unforeseeable emergency will be made only to the extent necessary to satisfy the emergency need, -6-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.plus an amount necessary to pay any taxes reasonably anticipated as a result of such payment, and will not be made to the extent the need is or may berelieved through reimbursement or compensation, by insurance or otherwise or by liquidation of the Director’s assets (to the extent such liquidation itselfwould not cause severe financial hardship). Any payment from a Director’s Deferral Account on account of an unforeseeable emergency shall be deemed tocancel any Deferral Election of the Director then in effect and the Director shall not be permitted to participate in the Plan until the next following calendaryear.7. No Assignment or Alienation of Benefits. Except as hereinafter provided with respect to a domestic relations order, a participant’s DeferralAccount may not be voluntarily or involuntarily assigned or alienated. In cases of marital dispute, Exelon will observe the terms of the Plan unless and untilordered to do otherwise pursuant to a domestic relations order, as defined in Section 414(p)(1)(B) of the Code. As a condition of participation, a participantagrees to hold Exelon harmless from any claim that arises out of Exelon’s obeying the terms of a domestic relations order, whether such order effects ajudgment of such court or is issued to enforce a judgment or order of another court.8. Amendment or Termination. The Plan may be altered, amended, suspended, or terminated at any time by the Exelon Board, provided that,except as otherwise provided herein or as permitted under Section 409A of the Code, no such action shall result in the distribution of amounts credited to theDeferral Accounts of any participant in any manner other than is provided in the Plan, nor shall such action reduce the availability of amounts previouslydeferred. To the extent permitted by Section 409A, the Exelon Board may, in its discretion, terminate the Plan with respect to Exelon, ComEd, PECO and/orBGE and accelerate the payment of all Deferral Accounts to the extent related to service on the Board for which the Plan is terminated:(a) within 12 months of a corporate dissolution taxed under Section 331 of the Code, or with the approval of a bankruptcy court pursuantto 11 U.S.C. §503(b)(1)(A), provided that the payments with respect to each such Deferral Account are included in the Director’s gross income in the later of(i) the calendar year in which the Plan termination occurs or (ii) the first calendar year in which the payments are administratively practicable; -7-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(b) in connection with a “change in control event,” as defined in, and to the extent permitted under, Treasury regulations promulgatedunder Section 409A of the Code or(c) upon any other termination event permitted under Section 409A of the Code.9. Compliance With Section 409A of the Code. The Plan is intended to comply with the provisions of Section 409A of the Code, and shall beinterpreted and construed accordingly. Exelon shall have the discretion and authority to amend the Plan at any time to satisfy any requirements ofSection 409A of the Code or guidance provided by the U.S. Treasury Department to the extent applicable to the Plan.10. Governing Law. The Plan shall be governed by the law of the Commonwealth of Pennsylvania to the extent not preempted by applicablefederal law. EXELON CORPORATION Executive Vice President -8-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 10.34EXELON CORPORATION2011 LONG-TERM INCENTIVE PLAN(As Amended Effective December 18, 2014)I. INTRODUCTION1.1 Purposes. The purposes of the Exelon Corporation 2011 Long-Term Incentive Plan (this “Plan”) are (i) to align the interests of the Company’sstockholders and the recipients of awards under this Plan by increasing the proprietary interest of such recipients in the Company’s growth and success, (ii) toadvance the interests of the Company by attracting and retaining officers and other key management employees and (iii) to motivate such persons to act inthe long-term best interests of the Company and its stockholders.1.2 Certain Definitions.“Affiliate” shall mean any Person (including a Subsidiary) that directly or indirectly controls, is controlled by, or is under common control with, theCompany. For purposes of this definition the term “control” with respect to any Person means the power to direct or cause the direction of management orpolicies of such Person, directly or indirectly, whether through the ownership of Voting Securities, by contract or otherwise.“Agreement” shall mean the written agreement evidencing an award hereunder between the Company and the recipient of such award.“Beneficial Owner” shall mean such term as defined in Rule 13d-3 under the Exchange Act.“Board” shall mean the Board of Directors of the Company.“Cause” shall mean (a) with respect to an employee whose entitlement to severance benefits upon termination of employment is governed by anindividual change in control agreement, the meaning of such term specified in such agreement, (b) with respect to an employee whose entitlement toseverance benefits upon termination of employment is governed by the Exelon Corporation Senior Management Severance Plan or any other executiveseverance plan, as in effect from time to time, the meaning of such term specified in such plan, or (c) with respect to any other employee, the meaning of suchterm specified in the Exelon Corporation Severance Benefit Plan, as amended from time to time, or any successor plan thereto, regardless of whether suchemployee is eligible to participate in such plan.“Change in Control” shall have the meaning set forth in Section 5.8.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.“Code” shall mean the Internal Revenue Code of 1986, as amended.“Committee” shall mean the Committee designated by the Board, consisting of two or more members of the Board, each of whom may be (i) a “Non-Employee Director” within the meaning of Rule 16b-3 under the Exchange Act, (ii) an “outside director” within the meaning of Section 162(m) of the Codeand (iii) “independent” within the meaning of the rules of the New York Stock Exchange or, if the Common Stock is not listed on the New York StockExchange, within the meaning of the rules of the principal national stock exchange on which the Common Stock is then traded.“Common Stock” shall mean the common stock, without par value, of the Company.“Company” shall mean Exelon Corporation, a Pennsylvania corporation, or any successor thereto.“Company Plan” shall have the meaning set forth in Section 5.8(b)(i).“Corporate Transaction” shall have the meaning set forth in Section 5.8(a).“Disability” shall have the meaning specified in any long term disability plan maintained by the Company in which the participant is eligible toparticipate; provided that a Disability shall not be deemed to have occurred until the Company has terminated such participant’s employment in connectionwith such disability and the participant has commenced the receipt of long-term disability benefits under such plan. If an participant is not eligible toparticipate in a long-term disability plan maintained by the Company, then Disability shall mean a termination of such participant’s employment by theCompany due to the inability of such participant to perform the essential functions such participant’s position, with or without reasonable accommodation,for a continuous period of at least twelve months, as determined solely by the Committee.“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.“Fair Market Value” shall mean the closing transaction price of a share of Common Stock as reported on the New York Stock Exchange on the date asof which such value is being determined or, if the Common Stock is not listed on the New York Stock Exchange, the closing transaction price of a share ofCommon Stock on the principal national stock exchange on which the Common Stock is traded on the date as of which such value is being determined or, ifthere shall be no reported transactions for such date, on the next preceding date for which transactions were reported; provided, however, that if the CommonStock is not listed on a national stock exchange or if Fair Market Value for any date cannot be so determined, Fair Market Value shall be determined by theCommittee by whatever means or method as the Committee, in the good faith exercise of its discretion, shall at such time deem appropriate and in accordancewith Section 409A of the Code. 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.“Free-Standing SAR” shall mean an SAR which is not granted in tandem with, or by reference to, an option, which entitles the holder thereof toreceive, upon exercise, shares of Common Stock (which may be Restricted Stock), cash or a combination thereof with an aggregate value equal to the excessof the Fair Market Value of one share of Common Stock on the date of exercise over the base price of such SAR, multiplied by the number of such SARswhich are exercised.“Good Reason” shall mean (i) with respect to an employee whose entitlement to severance benefits upon termination of employment is governed byan individual change in control agreement, the meaning of such term specified in such agreement, or (ii) with respect to a employee whose entitlement toseverance benefits upon termination of employment is governed by the Exelon Corporation Senior Management Severance Plan or any other executiveseverance plan, as in effect from time to time, the meaning of such term specified in such plan.“Incentive Stock Option” shall mean an option to purchase shares of Common Stock that meets the requirements of Section 422 of the Code, or anysuccessor provision, which is intended by the Committee to constitute an Incentive Stock Option.“Incumbent Board” shall have the meaning set forth in Section 5.8(b)(ii).“Nonqualified Stock Option” shall mean an option to purchase shares of Common Stock which is not an Incentive Stock Option.“Performance Measures” shall mean the criteria and objectives, established by the Committee, which shall be satisfied or met (i) as a condition to thegrant or exercisability of all or a portion of an option or SAR or (ii) during the applicable Restriction Period or Performance Period as a condition to thevesting of the holder’s interest, in the case of a Restricted Stock Award, of the shares of Common Stock subject to such award, or, in the case of a RestrictedStock Unit Award or Performance Unit Award, to the holder’s receipt of the shares of Common Stock subject to such award or of payment with respect to suchaward. To the extent necessary for an award to be qualified performance-based compensation under Section 162(m) of the Code and the regulationsthereunder, such criteria and objectives shall include one or more of the following measures, each of which may be based on absolute standards or peerindustry group comparatives and may be applied at various organizational levels (e.g., corporate, business unit, division): (1) cumulative shareholder valueadded (SVA), (2) customer satisfaction, (3) revenue, (4) primary or fully-diluted earnings per share of Common Stock, (5) net income, (6) total shareholderreturn, (7) earnings before interest taxes (EBIT), (8) cash flow, including operating cash flows, free cash flow, discounted cash flow return on investment andcash flow in excess of cost of capital, or any combination thereof, (9) economic value added, (10) return on equity, (11) return on capital, (12) return on assets,(13) net operating profits after taxes, (14) stock price increase, (15) return on sales, (16) debt to equity ratio, (17) payout ratio, (18) asset turnover, (19) ratio ofshare price to book value of shares, (20) price/earnings ratio, (21) employee satisfaction, (22) diversity, (23) market share, (24) operating income, (25) pre-taxincome, (26) safety, (27) diversification of business opportunities, (28) expense ratios, (29) total expenditures, (30) completion of key projects, (31) dividendpayout as percentage of net income, (32) earnings before interest, taxes, depreciation and amortization (EBITDA), or (33) any individual performanceobjective which is measured solely in terms of quantitative targets related to the 3Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Company, any Subsidiary or the Company’s or Subsidiary’s business. Such individual performance measures related to the Company, a Subsidiary or theCompany’s or Subsidiary’s business may include: (A) production-related factors such as generating capacity factor, performance against the INPO index,generating equivalent availability, heat rates and production cost, (B) transmission and distribution-related factors such as customer satisfaction, reliability(based on outage frequency and duration), and cost, (C) customer service-related factors such as customer satisfaction, service levels and responsiveness andbad debt collections or losses, and (D) relative performance against other similar companies in targeted areas. The measures may be weighted differently forholders of awards based on their management level and the extent to which their responsibilities are primarily corporate or business unit-related, and may bebased in whole or in part on the performance of the Company, a Subsidiary, division and/or other operational unit under one or more of such measures. In thesole discretion of the Committee, but subject to Section 162(m) of the Code, the Committee may amend or adjust the Performance Measures or other termsand conditions of an outstanding award in recognition of unusual or nonrecurring events affecting the Company or its financial statements or changes in lawor accounting principles.“Performance Option” shall mean an Incentive Stock Option or Nonqualified Stock Option, the grant of which or the exercisability of all or a portionof which is contingent upon the attainment of specified Performance Measures within a specified Performance Period.“Performance Period” shall mean any period designated by the Committee during which (i) the Performance Measures applicable to an award shallbe measured and (ii) the conditions to vesting applicable to an award shall remain in effect.“Performance Share Award” shall mean a Restricted Stock Award or Restricted Stock Unit Award, the vesting of which is subject to the attainment ofspecified Performance Measures within a specified Performance Period.“Performance Unit” shall mean a right to receive, contingent upon the attainment of specified Performance Measures within a specified PerformancePeriod and the expiration of any applicable Restriction Period, a specified cash amount or, in lieu thereof, shares of Common Stock having a Fair MarketValue equal to such cash amount.“Performance Unit Award” shall mean an award of Performance Units under this Plan.“Person” shall mean any individual, sole proprietorship, partnership, joint venture, limited liability company, trust, unincorporated organization,association, corporation, institution, public benefit corporation, entity or government instrumentality, division, agency, body or department.“Plan” shall have the meaning set forth in Section 1.1.“Prior Plan” shall mean the Exelon Corporation 2006 Long-Term Incentive Plan, as amended. 4Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.“Restricted Stock” shall mean shares of Common Stock which are subject to a Restriction Period and which may, in addition thereto, be subject to theattainment of specified Performance Measures within a specified Performance Period.“Restricted Stock Award” shall mean an award of Restricted Stock under this Plan.“Restricted Stock Unit” shall mean a right to receive one share of Common Stock or, in lieu thereof, the Fair Market Value of such share of CommonStock in cash, which shall be contingent upon the expiration of a specified Restriction Period and which may, in addition thereto, be contingent upon theattainment of specified Performance Measures within a specified Performance Period.“Restricted Stock Unit Award” shall mean an award of Restricted Stock Units under this Plan.“Restriction Period” shall mean any period designated by the Committee during which (i) the Common Stock subject to a Restricted Stock Awardmay not be sold, transferred, assigned, pledged, hypothecated or otherwise encumbered or disposed of, except as provided in this Plan or the Agreementrelating to such award, or (ii) the conditions to vesting applicable to a Restricted Stock Unit Award shall remain in effect.“Restrictive Covenant” shall have the meaning set forth in Section 2.3(g).“Retirement” shall mean the retirement of a holder of an award from employment with the Company on or after attaining the minimum age specifiedfor early or normal retirement in any then effective qualified defined benefit retirement plan of the Company in which such holder is a participant, providedthat such holder has also attained age 50 and completed at least ten years of service with the Company and the Subsidiaries. For purposes of this definition,the holder’s age and service shall be determined taking into account any deemed age or service awarded to the holder for benefit accrual purposes under anynonqualified defined benefit retirement plan of the Company in which the holder is a participant.“SAR” shall mean a stock appreciation right, which may be a Free-Standing SAR or a Tandem SAR.“SEC Person” shall mean any person (as such term is used in Rule 13d-5 under the Exchange Act) or group (as such term is defined in Sections 3(a)(9)and 13(d)(3) of the Exchange Act), other than (i) the Company or an Affiliate, or (ii) any employee benefit plan (or any related trust) of the Company or any ofits Affiliates.“Stock Award” shall mean a Restricted Stock Award or a Restricted Stock Unit Award, including any such award which is granted as a PerformanceShare Award.“Subsidiary” shall mean any corporation, limited liability company, partnership, joint venture or similar entity in which the Company owns, directlyor indirectly, an equity interest possessing more than 50% of the combined voting power of the total outstanding equity interests of such entity. 5Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.“Tandem SAR” shall mean an SAR which is granted in tandem with, or by reference to, an option (including a Nonqualified Stock Option grantedprior to the date of grant of the SAR), which entitles the holder thereof to receive, upon exercise of such SAR and surrender for cancellation of all or a portionof such option, shares of Common Stock (which may be Restricted Stock), cash or a combination thereof with an aggregate value equal to the excess of theFair Market Value of one share of Common Stock on the date of exercise over the base price of such SAR, multiplied by the number of shares of CommonStock subject to such option, or portion thereof, which is surrendered.“Tax Date” shall have the meaning set forth in Section 5.5.“Ten Percent Holder” shall have the meaning set forth in Section 2.1(a).“20% Owner” shall have the meaning set forth in Section 5.8(b)(i).“Voting Securities” shall mean with respect to a corporation, securities of such corporation that are entitled to vote generally in the election ofdirectors of such corporation.1.3 Administration. This Plan shall be administered by the Committee. Any one or a combination of the following awards may be made under this Plan toeligible persons: (i) options to purchase shares of Common Stock in the form of Incentive Stock Options or Nonqualified Stock Options (which may includePerformance Options), (ii) SARs in the form of Tandem SARs or Free-Standing SARs, (iii) Stock Awards in the form of Restricted Stock or Restricted StockUnits (which may include Performance Share Awards) and (iv) Performance Units. The Committee shall, subject to the terms of this Plan, select eligiblepersons for participation in this Plan and determine the form, amount and timing of each award to such persons and, if applicable, the number of shares ofCommon Stock, the number of SARs, the number of Restricted Stock Units and the number of Performance Units subject to such an award, the exercise priceor base price associated with the award, the time and conditions of exercise or settlement of the award and all other terms and conditions of the award,including, without limitation, the form of the Agreement evidencing the award. The Committee may, in its sole discretion and for any reason at any time,subject to the requirements of Section 162(m) of the Code and regulations thereunder in the case of an award intended to be qualified performance-basedcompensation, take action such that (i) any or all outstanding options and SARs shall become exercisable in part or in full, (ii) all or a portion of theRestriction Period applicable to any outstanding Restricted Stock or Restricted Stock Units shall lapse, (iii) all or a portion of the Performance Periodapplicable to any outstanding Performance Share Award or Performance Units shall lapse and (iv) the Performance Measures (if any) applicable to anyoutstanding award shall be deemed to be satisfied at the target or any other level not exceeding the maximum allowable under its terms. The Committee shall,subject to the terms of this Plan, interpret this Plan and the application thereof, establish rules and regulations it deems necessary or desirable for theadministration of this Plan and may impose, incidental to the grant of an award, conditions with respect to the award, such as limiting competitiveemployment or other activities. All such interpretations, rules, regulations and conditions shall be conclusive and binding on all parties. 6Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.The Committee may delegate some or all of its power and authority hereunder to the Board or, subject to applicable law, to the Chief Executive Officeror other officer of the Company as the Committee deems appropriate; provided, however, that (i) the Committee may not delegate its power and authority tothe Board or the Chief Executive Officer or other officer of the Company with regard to the grant of an award to any person who is a “covered employee”within the meaning of Section 162(m) of the Code or who, in the Committee’s judgment, is likely to be a covered employee at the time during the period anaward hereunder to such employee would be outstanding, (ii) the Committee may not delegate its power and authority to the Chief Executive Officer or otherofficer of the Company with regard to the selection for participation in this Plan of an officer or other person subject to Section 16 of the Exchange Act orwhose title with the Company is “executive vice president” or higher, or decisions concerning the timing, pricing or amount of an award to such an officer orother person and (iii) the awards granted by the Chief Executive Officer pursuant to such delegation shall not exceed the limits set forth in Section 1.6(c) and1.6(d).No member of the Board or Committee, and neither the Chief Executive Officer nor any other officer to whom the Committee delegates any of its powerand authority hereunder, shall be liable for any act, omission, interpretation, construction or determination made in connection with this Plan in good faith,and the members of the Board and the Committee and the Chief Executive Officer or other officer shall be entitled to indemnification and reimbursement bythe Company in respect of any claim, loss, damage or expense (including attorneys’ fees) arising therefrom to the full extent permitted by law (except asotherwise may be provided in the Company’s Articles of Incorporation and/or By-laws) and under any directors’ and officers’ liability insurance that may bein effect from time to time.A majority of the Committee shall constitute a quorum. The acts of the Committee shall be either (i) acts of a majority of the members of the Committeepresent at any meeting at which a quorum is present or (ii) acts approved in writing by all of the members of the Committee without a meeting.1.4 Eligibility. Participants in this Plan shall consist of such officers and other key management employees, and persons expected to become officers andother key management employees, of the Company and its Subsidiaries as the Committee in its sole discretion may select from time to time. The Committee’sselection of a person to participate in this Plan at any time shall not require the Committee to select such person to participate in this Plan at any other time.For purposes of this Plan, references to employment by the Company shall also mean employment by a Subsidiary.1.5 Shares Available. Subject to adjustment as provided in Section 5.7, the aggregate number of shares of Common Stock available for awards granted underthe Plan in the form of options, SARs, Stock Awards or Performance Units shall be the sum of (i) five million 7Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(5,000,000), plus (ii) the number of shares of Common Stock which as of the effective date of this Plan remain available for future awards pursuant toSection 1.5 of the Prior Plan, and reduced by the sum of the aggregate number of shares of Common Stock which become subject to outstanding options,outstanding Free-Standing SARs and outstanding Stock Awards granted under the Plan and shares of Common Stock delivered upon the settlement ofPerformance Units granted under the Plan. To the extent that shares of Common Stock subject to an outstanding option, SAR or stock award granted underthe Plan or any predecessor plan are not issued or delivered by reason of the expiration, termination, cancellation or forfeiture of such award (excludingshares subject to an option cancelled upon settlement in shares of a related tandem SAR or shares subject to a tandem SAR cancelled upon exercise of arelated option), then such shares of Common Stock shall again be available under this Plan. Shares of Common Stock to be delivered under this Plan shall bemade available from authorized and unissued shares of Common Stock, or authorized and issued shares of Common Stock reacquired and held as treasuryshares or otherwise or a combination thereof.1.6 Award Limits.(a) Subject to adjustment as provided in Section 5.7, no individual may be granted awards under the Plan during any calendar year that, in theaggregate, may be settled by delivery of more than two million (2,000,000) shares of Common Stock. In addition, with respect to awards the value of which isbased on the Fair Market Value of Common Stock and that may be settled in cash (in whole or in part), no individual may be paid during any calendar yearcash amounts relating to such awards that exceed the greater of the Fair Market Value of the number of shares of Common Stock set forth in the precedingsentence either at the date of grant or at the date of settlement. This Section 1.6(a) sets forth two separate limitations, so that awards that may be settled solelyby delivery of Common Stock will not operate to reduce the amount or value of cash-only awards, and vice versa; nevertheless, awards that may be settled inCommon Stock or cash must not exceed either limitation.(b) With respect to awards, the value of which is not based on the Fair Market Value of Common Stock, no individual may receive during any calendaryear cash or shares of Common Stock with a Fair Market Value at the date of settlement that, in the aggregate, exceeds five million dollars ($5,000,000).(c) Subject to adjustment as provided in Section 5.7, the number of shares of Common Stock subject to options and SARs granted in any single year bythe Chief Executive Officer, pursuant to a delegation by the Committee in accordance with Section 1.3 of this Plan, shall not exceed 1,200,000 in theaggregate or 40,000 with respect to any individual employee.(d) Subject to adjustment as provided in Section 5.7, the number of shares of Common Stock subject to Stock Awards and Performance Units granted inany single year by the Chief Executive Officer, pursuant to a delegation by the Committee in accordance with Section 1.3 of this Plan, shall not exceed600,000 in the aggregate or 20,000 with respect to any individual employee. 8Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.II. STOCK OPTIONS AND STOCK APPRECIATION RIGHTS2.1 Stock Options. The Committee may, in its discretion, grant options to purchase shares of Common Stock to such eligible persons as may be selected bythe Committee. Each option, or portion thereof, that is not an Incentive Stock Option, shall be a Nonqualified Stock Option. Each option shall be grantedwithin 10 years after the date on which this Plan is approved by the Board. To the extent that the aggregate Fair Market Value (determined as of the date ofgrant) of shares of Common Stock with respect to which options designated as Incentive Stock Options are exercisable for the first time by a participantduring any calendar year (under this Plan or any other plan of the Company, or any parent or Subsidiary) exceeds the amount (currently $100,000)established by the Code, such options shall constitute Nonqualified Stock Options.Options shall be subject to the following terms and conditions and shall contain such additional terms and conditions, not inconsistent with the termsof this Plan, as the Committee shall deem advisable:(a) Number of Shares and Purchase Price. The number of shares of Common Stock subject to an option and the purchase price per share of CommonStock purchasable upon exercise of the option shall be determined by the Committee; provided, however, that the purchase price per share of Common Stockpurchasable upon exercise of a Nonqualified Stock Option or an Incentive Stock Option shall not be less than 100% of the Fair Market Value of a share ofCommon Stock on the date of grant of such option; provided further, that if an Incentive Stock Option shall be granted to any person who, at the time suchoption is granted, owns capital stock possessing more than 10 percent of the total combined voting power of all classes of capital stock of the Company (or ofany parent or Subsidiary) (a “Ten Percent Holder”), the purchase price per share of Common Stock shall not be less than the price (currently 110% of FairMarket Value) required by the Code in order to constitute an Incentive Stock Option.(b) Option Period and Exercisability. The period during which an option may be exercised shall be determined by the Committee; provided, however,that no option shall be exercised later than 10 years after its date of grant; provided further, that if an Incentive Stock Option shall be granted to a Ten PercentHolder, such option shall not be exercised later than five years after its date of grant. The Committee may, in its discretion, determine that an option is to begranted as a Performance Option and may establish an applicable Performance Period and Performance Measures which shall be satisfied or met as acondition to the grant of such option or to the exercisability of all or a portion of such option. The Committee shall determine whether an option shallbecome exercisable in cumulative or non-cumulative installments and in part or in full at any time. An exercisable option, or portion thereof, may beexercised only with respect to whole shares of Common Stock.(c) Method of Exercise. An option may be exercised (i) by giving written notice to the Company specifying the number of whole shares of CommonStock to be purchased and accompanying such notice with payment therefor in full, and without any extension of credit, either (A) in cash, (B) by delivery(either actual delivery or by attestation procedures established by the Company) to the Company of previously owned whole shares of Common Stockhaving a 9Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Fair Market Value, determined as of the date of exercise, equal to the aggregate purchase price payable by reason of such exercise, (C) authorizing theCompany to withhold whole shares of Common Stock which would otherwise be delivered having an aggregate Fair Market Value, determined as of the dateof exercise, equal to the amount necessary to satisfy such obligation, provided that the Committee determines that such withholding of shares does not causethe Company to recognize an increased compensation expense under applicable accounting principles, (D) except as may be prohibited by applicable law, incash by a broker-dealer acceptable to the Company to whom the optionee has submitted an irrevocable notice of exercise or (E) a combination of (A), (B) and(C), in each case to the extent set forth in the Agreement relating to the option, (ii) if applicable, by surrendering to the Company any Tandem SARs whichare cancelled by reason of the exercise of the option and (iii) by executing such documents as the Company may reasonably request. Any fraction of a shareof Common Stock which would be required to pay such purchase price shall be disregarded and the remaining amount due shall be paid in cash by theoptionee. No shares of Common Stock shall be issued and no certificate representing Common Stock shall be delivered until the full purchase price thereforand any withholding taxes thereon, as described in Section 5.5, have been paid.2.2 Stock Appreciation Rights. The Committee may, in its discretion, grant SARs to such eligible persons as may be selected by the Committee. TheAgreement relating to an SAR shall specify whether the SAR is a Tandem SAR or a Free-Standing SAR.SARs shall be subject to the following terms and conditions and shall contain such additional terms and conditions, not inconsistent with the terms ofthis Plan, as the Committee shall deem advisable:(a) Number of SARs and Base Price. The number of SARs subject to an award shall be determined by the Committee. Any Tandem SAR related to anIncentive Stock Option shall be granted at the same time that such Incentive Stock Option is granted. The base price of a Tandem SAR shall be the purchaseprice per share of Common Stock of the related option. The base price of a Free-Standing SAR shall be determined by the Committee; provided, however, thatsuch base price shall not be less than 100% of the Fair Market Value of a share of Common Stock on the date of grant of such SAR.(b) Exercise Period and Exercisability. The Agreement relating to an award of SARs shall specify whether such award may be settled in shares ofCommon Stock (including shares of Restricted Stock) or cash or a combination thereof. The period for the exercise of an SAR shall be determined by theCommittee; provided, however, that no SAR shall be exercised later than 10 years after its date of grant; and provided, further, that no Tandem SAR shall beexercised later than the expiration, cancellation, forfeiture or other termination of the related option. The Committee may, in its discretion, establishPerformance Measures which shall be satisfied or met as a condition to the grant of an SAR or to the exercisability of all or a portion of an SAR. TheCommittee shall determine whether an SAR may be exercised in cumulative or non-cumulative installments and in part or in full at any time. An exercisableSAR, or portion thereof, may be exercised, in the case of a Tandem SAR, only with respect to whole shares of Common Stock and, in the case of aFree-Standing SAR, only with respect to a whole number of SARs. If an 10Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.SAR is exercised for shares of Restricted Stock, a certificate or certificates representing such Restricted Stock shall be issued in accordance withSection 3.2(c), or such shares shall be transferred to the holder in book entry form with restrictions on the Shares duly noted, and the holder of such RestrictedStock shall have such rights of a stockholder of the Company as determined pursuant to Section 3.2(d). Prior to the exercise of an SAR for shares of CommonStock, including Restricted Stock, the holder of such SAR shall have no rights as a stockholder of the Company with respect to the shares of Common Stocksubject to such SAR.(c) Method of Exercise. A Tandem SAR may be exercised (i) by giving written notice to the Company specifying the number of whole SARs which arebeing exercised, (ii) by surrendering to the Company any options which are cancelled by reason of the exercise of the Tandem SAR and (iii) by executingsuch documents as the Company may reasonably request. A Free-Standing SAR may be exercised (A) by giving written notice to the Company specifying thewhole number of SARs which are being exercised and (B) by executing such documents as the Company may reasonably request.2.3 Termination of Employment.(a) Retirement or Disability. Subject to Sections 2.3(e) and 2.3(g) below, and unless otherwise specified in the Agreement relating to an option or SAR,as the case may be, if the Company ceases to employ the holder of an option or SAR by reason of such holder’s Retirement or Disability, each option andSAR held by such holder shall be fully exercisable, and may thereafter be exercised by such holder (or such holder’s legal representative or similar person)until and including the earlier to occur of (i) the date which is five years after the effective date of such holder’s termination of employment and (ii) theexpiration date of the term of such option or SAR.(b) Death. Unless otherwise specified in the Agreement relating to an option or SAR, as the case may be, if the Company ceases to employ the holder ofan option or SAR by reason of such holder’s death, each option and SAR held by such holder shall be fully exercisable, and may thereafter be exercised bysuch holder’s executor, administrator, legal representative, beneficiary or similar person until and including the earlier to occur of (i) the date which is threeyears after the date of death and (ii) the expiration date of the term of such option or SAR.(c) Cause. If the Company ceases to employ the holder of an option or SAR due to a termination of employment by the Company for Cause, eachoption and SAR held by such holder shall be cancelled and cease to be exercisable as of the earlier to occur of (i) the effective date of such termination ofemployment and (ii) the date on which the holder first engaged in conduct giving rise to a termination for Cause, and the Company thereafter may require therepayment of any amounts received by such holder in connection with an exercise of such option or SAR following such cancellation date.(d) Other Termination. Subject to Sections 2.3(e), 2.3(f) and 2.3(g) below and unless otherwise specified in the Agreement relating to an option or SAR,as the case may be, if the Company ceases to employ the holder of an option or SAR for any reason other than as 11Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.described in Section 2.3(a) through Section 2.3(c), then each option and SAR held by such holder shall be exercisable only to the extent that such option orSAR is exercisable on the effective date of such holder’s termination of employment, and may thereafter be exercised by such holder (or such holder’s legalrepresentative or similar person) until and including the earlier to occur of (i) the date which is 90 days after the effective date of such holder’s termination ofemployment and (ii) the expiration date of the term of such option or SAR.(e) Death Following Termination of Employment. Unless otherwise specified in the Agreement relating to an option or SAR, as the case may be, if theholder of an option or SAR dies during the applicable post-termination exercise period described in Section 2.3(d), each option and SAR held by such holdershall be exercisable only to the extent that such option or SAR, as the case may be, is exercisable on the date of such holder’s death and may thereafter beexercised by the holder’s executor, administrator, legal representative, beneficiary or similar person until and including the earlier to occur of (i) the datewhich is one year after the date of death and (ii) the expiration date of the term of such option or SAR.(f) Breach of Restrictive Covenant. Notwithstanding Sections 2.3(a) through (e), if the holder of an option or SAR breaches his or her obligations to theCompany or any of its affiliates under a noncompetition, nonsolicitation, confidentiality, intellectual property or other restrictive covenant (a “RestrictiveCovenant”), each option and SAR held by such holder shall be cancelled and cease to be exercisable as of the date on which the holder first breached suchRestrictive Covenant, and the Company thereafter may require the repayment of any amounts received by such holder in connection with an exercise of suchoption or SAR following such cancellation date.(g) Certain Terminations After Change in Control. Unless otherwise specified in, and subject to all conditions set forth in, the Agreement relating to anoption or SAR, as the case may be, or any individual change in control agreement or severance plan, and notwithstanding any other provision of thisSection 2.3, if within 24 months following a Change in Control, the Company ceases to employ the holder of an option or SAR due to a termination ofemployment (i) by the Company other than for Cause, or (ii) with respect to a holder whose position is at least salary band E09 (or its equivalent), by theholder for Good Reason, such holder’s outstanding options shall immediately become fully exercisable and may thereafter be exercised by such holder (orsuch holder’s legal representative or similar person) until and including the earlier to occur of (A) the date which is five years after the effective date of suchholder’s termination of employment and (B) the expiration date of the term of such option or SAR.2.4 No Repricing. The Committee shall not without the approval of the stockholders of the Company, (i) reduce the purchase price or base price of anypreviously granted option or SAR, (ii) cancel any previously granted option or SAR in exchange for another option or SAR with a lower purchase price orbase price or (iii) cancel any previously granted option or SAR in exchange for cash or another award if the purchase price of such option or the base price ofsuch SAR exceeds the Fair Market Value of a share of Common Stock on the date of such cancellation, in each case, other than in connection with a Changein Control or the adjustment provisions set forth in Section 5.7. 12Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.III. STOCK AWARDS3.1 Stock Awards. The Committee may, in its discretion, grant Stock Awards to such eligible persons as may be selected by the Committee. The Agreementrelating to a Stock Award shall specify whether the Stock Award is a Restricted Stock Award or a Restricted Stock Unit Award. The Committee may, in itsdiscretion, determine that a Restricted Stock Award or Restricted Stock Unit Award is to be granted as a Performance Share Award and may establish anapplicable Performance Period and Performance Measures which shall be satisfied or met as a condition to the grant or vesting of all or a portion of suchaward.3.2 Terms of Restricted Stock Awards. Restricted Stock Awards shall be subject to the following terms and conditions and shall be subject to suchadditional terms and conditions, not inconsistent with the terms of this Plan, as the Committee shall deem advisable.(a) Number of Shares and Other Terms. The number of shares of Common Stock subject to a Restricted Stock Award and the Restriction Period andPerformance Measures (if any) applicable to a Restricted Stock Award shall be determined by the Committee.(b) Vesting and Forfeiture. The Agreement relating to a Restricted Stock Award shall provide, in the manner determined by the Committee, in itsdiscretion, and subject to the provisions of this Plan, for the vesting of the shares of Common Stock subject to such award (i) if the holder of such awardremains continuously in the employment of the Company during the specified Restriction Period and (ii) in the case of a Performance Share Award, ifspecified Performance Measures are satisfied or met during a specified Performance Period, and for the forfeiture of the shares of Common Stock subject tosuch award (x) if the holder of such award does not remain continuously in the employment of the Company during the specified Restriction Period or (y) inthe case of a Performance Share Award, if specified Performance Measures are not satisfied or met during a specified Performance Period. The restrictionsapplicable to each Performance Share Award shall lapse no earlier than one year after the applicable grant date, except to the extent an award Agreementprovides otherwise in the case of a Change in Control or a participant’s death, Disability or termination of employment.(c) Stock Issuance. During the Restriction Period, the shares of Restricted Stock shall be held by a custodian in book entry form with restrictions onsuch shares duly noted or, alternatively, a certificate or certificates representing a Restricted Stock Award shall be registered in the holder’s name and maybear a legend, in addition to any legend which may be required pursuant to Section 5.6, indicating that the ownership of the shares of Common Stockrepresented by such certificate is subject to the restrictions, terms and conditions of this Plan and the Agreement relating to the Restricted Stock Award. Allsuch certificates shall be deposited with the Company, together with stock powers or other instruments of assignment (including a power of attorney), eachendorsed in blank with a guarantee of signature if deemed necessary or appropriate, which would permit transfer to the Company of all or a portion of theshares of Common Stock subject to the Restricted Stock Award in the event such award is forfeited in whole or in part. Upon termination of any applicableRestriction Period (and the satisfaction or attainment of applicable Performance Measures), subject to the Company’s right to require 13Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.payment of any taxes in accordance with Section 5.5, the restrictions shall be removed from the requisite number of any shares of Common Stock that areheld in book entry form, and all certificates evidencing ownership of the requisite number of shares of Common Stock shall be delivered to the holder of suchaward.(d) Rights with Respect to Restricted Stock Awards. Unless otherwise set forth in the Agreement relating to a Restricted Stock Award, and subject to theterms and conditions of a Restricted Stock Award, the holder of such award shall have all rights as a stockholder of the Company, including, but not limitedto, voting rights, the right to receive dividends and the right to participate in any capital adjustment applicable to all holders of Common Stock; provided,however, that (i) a distribution with respect to shares of Common Stock, other than a regular cash dividend, and (ii) a regular cash dividend with respect toshares of Common Stock that are subject to performance-based vesting conditions, in each case shall be deposited with the Company and shall be subject tothe same restrictions as the shares of Common Stock with respect to which such distribution was made.3.3 Terms of Restricted Stock Unit Awards. Restricted Stock Unit Awards shall be subject to the following terms and conditions and shall contain suchadditional terms and conditions, not inconsistent with the terms of this Plan, as the Committee shall deem advisable.(a) Number of Shares and Other Terms. The number of shares of Common Stock subject to a Restricted Stock Unit Award and the Restriction Period andPerformance Measures (if any) applicable to a Restricted Stock Unit Award shall be determined by the Committee.(b) Vesting and Forfeiture. The Agreement relating to a Restricted Stock Unit Award shall provide, in the manner determined by the Committee, in itsdiscretion, and subject to the provisions of this Plan, for the vesting of such Restricted Stock Unit Award (i) if the holder of such award remains continuouslyin the employment of the Company during the specified Restriction Period and (ii) in the case of a Performance Share Award, if specified PerformanceMeasures are satisfied or met during a specified Performance Period, and for the forfeiture of the shares of Common Stock subject to such award (x) if theholder of such award does not remain continuously in the employment of the Company during the specified Restriction Period or (y) in the case of aPerformance Share Award, if specified Performance Measures are not satisfied or met during a specified Performance Period. Each Performance Share Awardshall become vested no earlier than one year after the applicable grant date, except to the extent an award Agreement provides otherwise in the case of aChange in Control or a participant’s death, Disability or termination of employment.(c) Settlement of Vested Restricted Stock Unit Awards. The Agreement relating to a Restricted Stock Unit Award shall specify (i) whether such awardmay be settled in shares of Common Stock, including Restricted Stock, or cash or a combination thereof and (ii) whether the holder thereof shall be entitledto receive, on a current or deferred basis, dividend equivalents and, if determined by the Committee, interest on, or the deemed reinvestment of, any deferreddividend equivalents, with respect to the number of shares of Common Stock subject to such award. Prior to the settlement of a Restricted Stock Unit Award,the holder of such award shall have no rights as a stockholder of the Company with respect to the shares of Common Stock subject to such award. 14Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.3.4 Termination of Employment. All of the terms relating to the satisfaction of Performance Measures and the termination of the Restriction Period orPerformance Period relating to a Stock Award, or any forfeiture and cancellation of such award upon a termination of employment with the Company of theholder of such award, whether by reason of Disability, Retirement, death or any other reason, shall be determined by the Committee and set forth in theapplicable award Agreement.IV. PERFORMANCE UNIT AWARDS4.1 Performance Unit Awards. The Committee may, in its discretion, grant Performance Unit Awards to such eligible persons as may be selected by theCommittee.4.2 Terms of Performance Unit Awards. Performance Unit Awards shall be subject to the following terms and conditions and shall be subject to suchadditional terms and conditions, not inconsistent with the terms of this Plan, as the Committee shall deem advisable.(a) Number of Performance Units and Performance Measures. The number of Performance Units subject to a Performance Unit Award and thePerformance Measures and Performance Period applicable to a Performance Unit Award shall be determined by the Committee.(b) Vesting and Forfeiture. The Agreement relating to a Performance Unit Award shall provide, in the manner determined by the Committee, in itsdiscretion, and subject to the provisions of this Plan, for the vesting of such Performance Unit Award if the specified Performance Measures are satisfied ormet during the specified Performance Period and for the forfeiture of such award if the specified Performance Measures are not satisfied or met during thespecified Performance Period.(c) Settlement of Vested Performance Unit Awards. The Agreement relating to a Performance Unit Award shall specify whether such award may besettled in shares of Common Stock (including shares of Restricted Stock) or cash or a combination thereof. If a Performance Unit Award is settled in shares ofRestricted Stock, such shares of Restricted Stock shall be issued to the holder in book entry form or a certificate or certificates representing such RestrictedStock shall be issued in accordance with Section 3.2(c) and the holder of such Restricted Stock shall have such rights as a stockholder of the Company asdetermined pursuant to Section 3.2(d). Prior to the settlement of a Performance Unit Award in shares of Common Stock, including Restricted Stock, the holderof such award shall have no rights as a stockholder of the Company.4.3 Termination of Employment. All of the terms relating to the satisfaction of Performance Measures and the termination of the Performance Period relatingto a Performance Unit Award, or any forfeiture and cancellation of such award upon a termination of employment with the Company of the holder of suchaward, whether by reason of Disability, Retirement, death or any other reason, shall be determined by the Committee and set forth in the applicable awardAgreement. 15Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.V. GENERAL5.1 Effective Date and Term of Plan. This Plan shall be submitted to the stockholders of the Company for approval at the Company’s 2010 annual meetingof stockholders and, if approved by the affirmative vote of a majority of the shares of Common Stock present in person or represented by proxy at such annualmeeting of stockholders, shall become effective as of January 1, 2011. This Plan shall terminate ten (10) years after its effective date, unless terminated earlierby the Committee. Termination of this Plan shall not affect the terms or conditions of any award granted prior to termination.Awards hereunder may be made at any time prior to the termination of this Plan, provided that, subject to Section 2.1, no award may be made later thanten (10) years after the effective date of this Plan. In the event that this Plan is not approved by the stockholders of the Company, this Plan and any awardshereunder shall be void and of no force or effect.5.2 Amendments. The Committee may amend this Plan as it shall deem advisable, subject to any requirement of stockholder approval required by applicablelaw, rule or regulation, including Section 162(m) of the Code and any rule of the New York Stock Exchange, or, if the Common Stock is not listed on the NewYork Stock Exchange, any rule of the principal national stock exchange on which the Common Stock is then traded; provided, however, that no amendmentmay impair the rights of a holder of an outstanding award without the consent of such holder.5.3 Agreement. Each award under this Plan shall be evidenced by an Agreement setting forth the terms and conditions applicable to such award. No awardshall be valid until an Agreement is executed by the Company and the recipient of such award and, upon execution by each party and delivery of theAgreement to the Company within the time period specified by the Company, such award shall be effective as of the effective date set forth in the Agreement.5.4 Non-Transferability. No award shall be transferable other than by will, the laws of descent and distribution or pursuant to beneficiary designationprocedures approved by the Company or, to the extent expressly permitted in the Agreement relating to such award, to the holder’s family members, a trust orentity established by the holder for estate planning purposes or a charitable organization designated by the holder. Except to the extent permitted by theforegoing sentence or the Agreement relating to an award, each award may be exercised or settled during the holder’s lifetime only by the holder or theholder’s legal representative or similar person. Except as permitted by the second preceding sentence, no award may be sold, transferred, assigned, pledged,hypothecated, encumbered or otherwise disposed of (whether by operation of law or otherwise) or be subject to execution, attachment or similar process.Upon any attempt to so sell, transfer, assign, pledge, hypothecate, encumber or otherwise dispose of any award, such award and all rights thereunder shallimmediately become null and void. 16Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.5.5 Tax Withholding. The Company shall have the right to require, prior to the issuance or delivery of any shares of Common Stock or the payment of anycash pursuant to an award made hereunder, or upon the vesting of any award that is considered deferred compensation, payment by the holder of such awardof any federal, state, local or other taxes which may be required to be withheld or paid in connection with such award. An Agreement may provide that (i) theCompany shall withhold whole shares of Common Stock which would otherwise be delivered to a holder, having an aggregate Fair Market Value determinedas of the date the obligation to withhold or pay taxes arises in connection with an award (the “Tax Date”), or withhold an amount of cash which wouldotherwise be payable to a holder, in the amount necessary to satisfy any such obligation or (ii) the holder may satisfy any such obligation by any of thefollowing means: (A) a cash payment to the Company, (B) authorizing the Company to withhold whole shares of Common Stock which would otherwise bedelivered having an aggregate Fair Market Value, determined as of the Tax Date, or withhold an amount of cash which would otherwise be payable to aholder, equal to the amount necessary to satisfy any such obligation, (C) in the case of the exercise of an option and except as may be prohibited byapplicable law, a cash payment by a broker-dealer acceptable to the Company to whom the optionee has submitted an irrevocable notice of exercise or(D) any combination of (A) and (B), in each case to the extent set forth in the Agreement relating to the award. Shares of Common Stock to be delivered orwithheld may not have an aggregate Fair Market Value in excess of the amount determined by applying the minimum statutory withholding rate. Anyfraction of a share of Common Stock which would be required to satisfy such an obligation shall be disregarded and the remaining amount due shall be paidin cash by the holder.5.6 Restrictions on Shares. Each award made hereunder shall be subject to the requirement that if at any time the Company determines that the listing,registration or qualification of the shares of Common Stock subject to such award upon any securities exchange or under any law, or the consent or approvalof any governmental body, or the taking of any other action is necessary or desirable as a condition of, or in connection with, the delivery of sharesthereunder, such shares shall not be delivered unless such listing, registration, qualification, consent, approval or other action shall have been effected orobtained, free of any conditions not acceptable to the Company. The Company may require that certificates evidencing shares of Common Stock deliveredpursuant to any award made hereunder bear a legend indicating that the sale, transfer or other disposition thereof by the holder is prohibited except incompliance with the Securities Act of 1933, as amended, and the rules and regulations thereunder.5.7 Adjustment. In the event any stock split, stock dividend, recapitalization, reorganization, merger, consolidation, combination, exchange of shares,liquidation, spin-off or other similar change in capitalization or event, or any distribution to holders of Common Stock (other than a regular cash dividend)occurs on or after the date this Plan is approved by the stockholders of the Company, the number and class of securities available for all awards under thisPlan, the maximum number of securities with respect to which awards may be granted during any year to any one person, the maximum number of sharessubject to awards granted during any year by the Chief Executive Officer, the number and class of securities subject to each outstanding option and thepurchase price per security, and the terms of each outstanding SAR, Restricted Stock Award, Restricted Stock Unit Award, Performance Share Award and 17Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Performance Unit Award, including the number and class of securities subject thereto, shall be appropriately adjusted by the Committee, such adjustments tobe made in the case of outstanding options and SARs without an increase in the aggregate purchase price or base price. The decision of the Committeeregarding any such adjustment shall be final, binding and conclusive. If any such adjustment would result in a fractional security being (a) available underthis Plan, such fractional security shall be disregarded, or (b) subject to an award under this Plan, the Company shall pay the holder of such award, inconnection with the first vesting, exercise or settlement of such award, in whole or in part, occurring after such adjustment, an amount in cash determined bymultiplying (i) the fraction of such security (rounded to the nearest hundredth) by (ii) the excess, if any, of (A) the Fair Market Value on the vesting, exerciseor settlement date over (B) the exercise or base price, if any, of such award.5.8 Corporate Transactions; Change in Control.(a) If the Company shall be a party to a reorganization, merger, or consolidation or sale or other disposition of more than 50% of the operating assets ofthe Company (determined on a consolidated basis), other than in connection with a sale-leaseback or other arrangement resulting in the continued utilizationof such assets (or the operating products of such assets) (a “Corporate Transaction”), the Board (as constituted prior to any Change in Control resulting fromsuch Corporate Transaction) may, in its discretion:(i) require that (A) some or all outstanding options and SARs shall immediately become exercisable in full or in part, (B) the RestrictionPeriod applicable to some or all outstanding Restricted Stock Awards and Restricted Stock Unit Awards shall lapse in full or in part, (C) thePerformance Period applicable to some or all outstanding Performance Share Awards and Performance Unit Awards shall lapse in full or in part,and (D) the Performance Measures applicable to some or all outstanding awards shall be deemed to be satisfied at the target or any other level notexceeding the maximum levels allowable under their respective terms;(ii) require that shares of capital stock of the corporation resulting from such Corporate Transaction, or a parent corporation thereof, besubstituted for some or all of the shares of Common Stock subject to an outstanding award, with an appropriate and equitable adjustment to suchaward as determined by the Board in accordance with Section 5.7; and/or(iii) require outstanding awards, in whole or in part, to be surrendered to the Company by the holder, and to be immediately cancelled bythe Company, and to provide for the holder to receive (A) a cash payment in an amount equal to (1) in the case of an option or an SAR, thenumber of shares of Common Stock then subject to the portion of such option or SAR surrendered, to the extent such option or SAR is thenexercisable or becomes exercisable pursuant to clause (i), multiplied by the excess, if any, of the Fair Market Value of a share of Common Stockas of the date of the Corporate Transaction, over the purchase price or base 18Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.price per share of Common Stock subject to such option or SAR, (2) in the case of a Stock Award, the number of shares of Common Stock thensubject to the portion of such award surrendered, to the extent the Restriction Period and Performance Period, if any, on such Stock Award havelapsed or will lapse pursuant to clause (i) and to the extent that the Performance Measures, if any, have been satisfied or are deemed satisfiedpursuant to clause (i), multiplied by the Fair Market Value of a share of Common Stock as of the date of the Corporate Transaction, and (3) in thecase of a Performance Unit Award, the value of the Performance Units then subject to the portion of such award surrendered, to the extent thePerformance Period applicable so such award has lapsed or will lapse pursuant to clause (i) and to the extent the Performance Measuresapplicable to such award have been satisfied or are deemed satisfied pursuant to clause (i); (B) shares of capital stock of the corporation resultingfrom such Corporate Transaction, or a parent corporation thereof, having a fair market value not less than the amount determined under clause(A) above; or (C) a combination of the payment of cash pursuant to clause (A) above and the issuance of shares pursuant to clause (B) above.(b) For purposes of Sections 2.3(f) and 5.8(a), “Change in Control” shall mean, except as otherwise provided below, the first to occur of any of thefollowing events:(i) any SEC Person becomes the Beneficial Owner of 20% or more of the then outstanding common stock of the Company or of VotingSecurities representing 20% or more of the combined voting power of all the then outstanding Voting Securities of the Company (such an SECPerson, a “20% Owner”); provided, however, that for purposes of this subsection (i), the following acquisitions shall not constitute a Change inControl: (1) any acquisition directly from the Company (excluding any acquisition resulting from the exercise of an exercise, conversion orexchange privilege unless the security being so exercised, converted or exchanged was acquired directly from the Company), (2) any acquisitionby the Company, (3) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporationcontrolled by the Company (a “Company Plan”), or (4) any acquisition by any corporation pursuant to a transaction which complies withparagraphs (A), (B) and (C) of subsection (iii) of this definition; provided further, that for purposes of clause (2), if any 20% Owner of theCompany other than the Company or any Company Plan becomes a 20% Owner by reason of an acquisition by the Company, and such 20%Owner of the Company shall, after such acquisition by the Company, become the Beneficial Owner of any additional outstanding commonshares of the Company or any additional outstanding Voting Securities of the Company (other than pursuant to any dividend reinvestment planor arrangement maintained by the Company) and such beneficial ownership is publicly announced, such additional beneficial ownership shallconstitute a Change in Control; or 19Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(ii) Individuals who, as of the effective date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at leasta majority of the Incumbent Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, ornomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising theIncumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, anysuch individual whose initial assumption of office occurs as a result of an actual or threatened election contest (as such terms are used inRule 14a-11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Personother than the Board; or(iii) Consummation of a Corporate Transaction by the Company; excluding, however, a Corporate Transaction pursuant to which:(A) all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstanding commonstock of Company and outstanding Voting Securities of the Company immediately prior to such Corporate Transaction beneficially own,directly or indirectly, more than 60% of, respectively, the then-outstanding shares of common stock and the combined voting power ofthe then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporationresulting from such Corporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns theCompany or all or substantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially thesame proportions as their ownership immediately prior to such Corporate Transaction of the outstanding common stock of Company andoutstanding Voting Securities of the Company, as the case may be;(B) no SEC Person (other than the corporation resulting from such Corporate Transaction, and any Person which beneficiallyowned, immediately prior to such corporate Transaction, directly or indirectly, 20% or more of the outstanding common stock of theCompany or the outstanding Voting Securities of the Company, as the case may be) becomes a 20% Owner, directly or indirectly, of thethen-outstanding common stock of the corporation resulting from such Corporate Transaction or the combined voting power of theoutstanding voting securities of such corporation; and(C) individuals who were members of the Incumbent Board will constitute at least a majority of the members of the board ofdirectors of the corporation resulting from such Corporate Transaction; or 20Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(iv) Approval by the Company’s shareholders of a plan of complete liquidation or dissolution of the Company, other than a plan ofliquidation or dissolution which results in the acquisition of all or substantially all of the assets of the Company by an affiliated company.Notwithstanding the occurrence of any of the foregoing events, a Change in Control shall not occur with respect to an award if, in advance of such event, theholder of such award agrees in writing that such event shall not constitute a Change in Control.5.9 Deferrals. The Committee may determine that the delivery of shares of Common Stock or the payment of cash, or a combination thereof, upon theexercise or settlement of all or a portion of any award made hereunder shall be deferred, or the Committee may, in its sole discretion, approve deferralelections made by holders of awards. Deferrals shall be for such periods and upon such terms as shall be set forth in a deferral plan or program established bythe Committee in its sole discretion in accordance with Section 409A of the Code.5.10 No Right of Participation or Employment. Unless otherwise set forth in an employment agreement, no person shall have any right to participate in thisPlan. Neither this Plan nor any award made hereunder shall confer upon any person any right to continued employment with the Company, any Subsidiary orany affiliate of the Company or affect in any manner the right of the Company, any Subsidiary or any affiliate of the Company to terminate the employmentof any person at any time without liability hereunder.5.11 Rights as Stockholder. No person shall have any right as a stockholder of the Company with respect to any shares of Common Stock or other equitysecurity of the Company which is subject to an award hereunder unless and until such person becomes a stockholder of record with respect to such shares ofCommon Stock or equity security.5.12 Designation of Beneficiary. A holder of an award may file with the Committee a written designation of one or more persons as such holder’s beneficiaryor beneficiaries (both primary and contingent) in the event of the holder’s death or incapacity. To the extent an outstanding option or SAR granted hereunderis exercisable, such beneficiary or beneficiaries shall be entitled to exercise such option or SAR pursuant to procedures prescribed by the Committee.Each beneficiary designation shall become effective only when filed in writing with the Committee during the holder’s lifetime on a form prescribedby the Committee. The spouse of a married holder domiciled in a community property jurisdiction shall join in any designation of a beneficiary other thansuch spouse. The filing with the Committee of a new beneficiary designation shall cancel all previously filed beneficiary designations.If a holder fails to designate a beneficiary, or if all designated beneficiaries of a holder predecease the holder, then each outstanding option and SARhereunder held by such holder, to the extent exercisable, may be exercised by such holder’s executor, administrator, legal representative or similar person. 21Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.5.13 Governing Law. This Plan, each award hereunder and the related Agreement, and all determinations made and actions taken pursuant thereto, to theextent not otherwise governed by the Code or the laws of the United States, shall be governed by the laws of the Commonwealth of Pennsylvania andconstrued in accordance therewith without giving effect to principles of conflicts of laws.5.14 Foreign Employees. Without amending this Plan, the Committee may grant awards to eligible persons who are foreign nationals on such terms andconditions different from those specified in this Plan as may in the judgment of the Committee be necessary or desirable to foster and promote achievement ofthe purposes of this Plan and, in furtherance of such purposes the Committee may make such modifications, amendments, procedures, subplans and the like asmay be necessary or advisable to comply with provisions of laws in other countries or jurisdictions in which the Company or its Subsidiaries operates or hasemployees. 22Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 10.34.1EXELON CORPORATIONLONG-TERM INCENTIVE PROGRAM(As amended and restated as of January 1, 2014)1. Purpose. The purpose of this Exelon Corporation Long-Term Incentive Program (the “Program”) is to set forth certain provisions which shallbe deemed a part of, and govern, equity compensation awards granted by Exelon Corporation, a Pennsylvania corporation (the “Company”), on or afterJanuary 1, 2011 to executives, key managers and other select management employees pursuant to the Exelon Corporation 2011 Long-Term Incentive Plan, asamended (the “Plan”).2. Certain Definitions.Except as otherwise set forth herein, the defined terms used in this Program shall have the meanings set forth below or in the Plan.(a) “Administrator” shall have the meaning set forth in Section 14 below.(b) “Award” shall mean an award granted under this Program.(c) “Award Notice” shall mean a notice of a Participant’s Award, issued by the Company in written or electronic form, which shall set forththe type of the Award, the number of shares (or target share opportunity that, together with the Program summary, sets forth the number of shares) ofCommon Stock subject to such Award and any other terms of the Award not set forth in the Plan, this Program or the Program summary.(d) “Board” shall mean the board of directors of the Company.(e) “Transition Award” shall mean a Performance Share Unit Award granted on a one-time basis in 2013 (or 2014, in certain cases such asnew hires, promotions or transfers) in order to transition from a one-year Performance Cycle to a three-year Performance Cycle.(f) “Committee” shall mean the compensation committee of the Board.(g) “Dividend Payment Date” shall mean each date on which the Company pays a regular cash dividend to record owners of shares ofCommon Stock.(h) “Earned Shares” shall mean shares of Common Stock (or cash representing shares, as applicable) subject to a Performance Share UnitAward that are earned based on the achievement of the performance goals for the applicable Performance Cycle (or portion thereof, in the case ofTransition Awards).(i) “Effective Date” shall mean January 1, 2011.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(j) “First Tranche” shall mean one-third of the Performance Share Units granted under a Transition Award.(k) “Grant Date” shall mean the date on which an Award is granted, as set forth in the applicable Award Notice.(l) “Option” shall mean a nonqualified option to purchase shares of Common Stock upon and subject to the satisfaction of the vestingconditions set forth in Section 5 of this Program.(m) “Participant” shall mean the recipient of an Award granted under this Program.(n) “Performance Cycle” shall mean (A) for Performance Share Unit Awards granted prior to January 1, 2013, the one-year periodbeginning on January 1 of the year in which the Award is granted (and any applicable look-back period), (B) for the Transition Awards, the two-yearperiod beginning on January 1, 2013 and (C) for Performance Share Unit Awards granted on or after January 1, 2013 (other than Transition Awards) andPerformance Cash Awards granted on or after January 1, 2014, the three-year period beginning on January 1of the year in which the Performance ShareUnit Award is granted.(o) “Performance Cash Unit” shall mean a right granted to a Participant employed in a Utility Company to receive an amount of cashsubject to the achievement of the applicable performance goals and the satisfaction of the vesting conditions set forth in Section 3 of this Program.(p) “Performance Share Unit” shall mean a right to receive shares of Common Stock or a cash equivalent (as applicable) subject to theachievement of the applicable performance goals and the satisfaction of the vesting conditions set forth in Section 3 of this Program.(q) “Restricted Stock Unit” shall mean a right to receive shares of Common Stock upon and subject to the satisfaction of the vestingconditions set forth in Section 4 of this Program.(r) “Restrictive Covenants” shall mean any noncompetition, nonsolicitation, confidentiality, intellectual property or other restrictivecovenants to which a Participant is subject, required as a condition to receipt of an Award, or which is contained in any other agreement between theParticipant and the Company or any of its affiliates.(s) “Retirement” shall mean a Participant’s termination of employment (other than a termination upon death, disability or involuntarytermination for cause) on or after the date as of which the Participant has attained age 50 (age 55 with respect to Awards granted on or after January 1,2013) and completed at least ten years of service with the Company and the Subsidiaries. For purposes of this definition, the holder’s age and serviceshall be determined taking into account any deemed age or service awarded to the holder for benefit accrual purposes under any nonqualified definedbenefit retirement plan of the Company in which the holder is a participant. 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(t) “Second Tranche” shall mean two-thirds of the Performance Share Units granted under a Transition Award(u) “Utility Company” shall mean Baltimore Gas & Electric Company, Commonwealth Edison Company, PECO Energy Company and theExelon Utility Group within Exelon Business Services Company, LLC.3. Long Term Performance Share Award and Performance Cash Award Program.(a) Granting of Awards. Within the first 90 days of each Performance Cycle beginning on or after the Effective Date, the Committee maygrant Performance Share Unit Awards to employees who are employed in a Vice President or more senior position, including without limitation NuclearPlant Managers, as selected by the Committee in its sole discretion. Effective January 1, 2014, the Committee may grant Performance Cash Units inlieu of Performance Share Unit Awards to such designated employees who are employed in a Utility Company. Performance Share Unit Awards andPerformance Cash Units shall be subject to the respective applicable terms and conditions set forth in this Section 3, and shall contain such additionalterms and conditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set forth in the applicable Programsummary or Award Notice.(b) Number of Shares and Other Terms. The number of shares of Common Stock represented by a Performance Share Unit Award (“EarnedShares”) for any Performance Cycle shall be determined based on the achievement of performance goals established by the Committee and set forth inthe Program summary for such Performance Cycle and the administrative guidelines approved by the Committee. Each performance goal shall beassigned a weighting and scored at the end of each calendar year within the Performance Cycle. For Performance Cycles beginning on or afterJanuary 1, 2013, at the end of the Performance Cycle, the number of Earned Shares is determined based on the average of the annual performanceresults, subject to adjustment as set forth in the Program summary and/or administrative guidelines. Notwithstanding the foregoing, the maximumnumber of shares of Common Stock that may become subject to Performance Share Unit Awards granted in any calendar year to Participants theCompany has determined as of the Grant Date may be “covered employees” (within the meaning of Section 162(m)(3) of the Code) for such year or forany subsequent year in which such Award may be outstanding, shall be equal to the lesser of (i) the number determined by (A) multiplying 1.5% of theCompany’s Operating Income for such year by the allocation percentage approved by Committee for such Participant within the first 90 days of theapplicable Performance Cycle and (B) dividing such dollar amount by the closing price of a share of Common Stock on the last trading day of suchyear and (ii) the per person limit set forth in Section 1.6 of the Plan. For purposes of this Section 3(b), the “Operating Income” of the Company for suchyear shall be as reported in the Company’s financial statements for such year according to generally accepted accounting principles and as reviewed oraccepted, as the case may be, 3Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.by the Company’s independent public accountants, and certified by the Committee in accordance with section 162(m) of the Code. The Committeereserves the right in its sole discretion to determine that the number of Earned Shares for any Performance Cycle shall be zero in the event of materiallyadverse business or financial circumstances as determined by the Committee.(c) Vesting and Forfeiture. (i)Awards Granted prior to January 1, 2013. Except as provided in Section 3(f)(i) of the Program, Earned Shares granted prior to January 1,2013 shall become vested (i) on the date of the first regular meeting of the Committee held in the calendar year following the calendaryear in which the Grant Date occurs with respect to one-third of the number of Earned Shares, (ii) on the date of the first regular meetingof the Committee held in the second calendar year following the calendar in which the Grant Date occurs with respect to an additionalone-third of the number of Earned Shares, and (iii) on the date of the first regular meeting of the Committee held in the third calendaryear following the calendar year in which the Grant Date occurs with respect to the remaining Earned Shares (but, with respect to eachsuch year, not later than March 15), in each case subject to the Participant’s continuous employment with the Company through theapplicable vesting date. (ii)Transition Awards. Except as provided in Section 3(f)(ii) of the Program, Performance Share Units subject to a Transition Award shall beearned and become vested (i) with respect to the First Tranche, on the date of the first regular meeting of the Committee held in 2014 and(ii) with respect to the Second Tranche, on the date of the first regular meeting of the Committee held in 2015 (but, with respect to eachsuch year, not later than March 15), in each case subject to the Participant’s continuous employment with the Company through theapplicable vesting date. (iii)Awards Granted on or after January 1, 2013 (Other than Transition Awards). Except as provided in Section 3(f)(ii) of the Program,Performance Share Units and Performance Cash Units subject to an Award (other than a Transition Award) and granted on or afterJanuary 1, 2013 shall be earned and become fully vested on the date of the first regular meeting of the Committee held in the thirdcalendar year following the calendar year in which the Grant Date occurs (but, with respect to each such Performance Cycle, not laterthan March 15 of such year), in each case subject to the Participant’s continuous employment with the Company through the applicablevesting date.(d) Dividend Equivalents. As of each Dividend Payment Date, the Company shall pay to the Participant a cash payment in an amountequal to the dollar amount of the cash dividend paid per share of Common Stock multiplied by the number of Earned Shares that are subject to aPerformance Share Unit Award immediately prior to the record date for such Dividend Payment Date, but that have not been issued pursuant toSection 3(e) as of such record date. 4Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(e) Settlement of Vested Awards. Subject to the withholding of taxes pursuant to Section 8 of the Program, within 30 days after the vestingof a Performance Share Unit Award, in whole or in part (or at such later time as may be required pursuant to this Section 3(e)), the Company shall issueor transfer to the Participant the number of Earned Shares that have become vested. The Company may effect such transfer either by the delivery of oneor more certificates of Common Stock to the Participant or by an appropriate entry on the books of the Company or of a duly authorized transfer agentof the Company, and in either case by issuing such shares in the Participant’s name or in such other name as is acceptable to the Company anddesignated in writing by the Participant. All such Awards payable for 2012 or thereafter shall be paid 50% in Common Stock and 50% in cash;provided, however, that effective for Awards granted on or after January 1, 2013 (including Transition Awards), a Participant whose title is ExecutiveVice President or above and who has achieved 200% or more of his or her stock ownership target by September 30 of the calendar year prior to payoutof the Award shall be paid in cash. The Company shall pay all original issue or transfer taxes and all fees and expenses incident to such delivery,except as otherwise provided in Section 8 of the Program. Prior to the settlement of a Performance Share Unit Award, the holder of such Award shallhave no rights as a stockholder of the Company with respect to the shares of Common Stock subject to such Award. Performance Cash Awards shall bepaid in cash upon vesting. Notwithstanding the foregoing, if a Participant is a “Specified Employee,” within the meaning of section 409A of the Code,and such Participant is or will become eligible for Retirement prior to the calendar year in which the Performance Share Unit Award is scheduled tobecome fully vested, then any Earned Shares subject to the Award or payment under a Performance Cash Unit which become vested upon theParticipant’s termination of employment in accordance with Section 3(f) of this Program shall be issued to the Participant as of the earlier to occur ofthe six-month anniversary of such Participant’s separation from service or the date of the Participant’s death.(f) Termination of Employment. Except as otherwise provided in this Program or the Plan: (i)Retirement, Disability, Death or Involuntary Termination Without Cause – Awards Granted prior to January 1, 2013. If a Participant’semployment with the Company terminates by reason of Retirement, Disability, death or an involuntary termination of employment bythe Company for a reason other than Cause, and such Participant has not breached his or her obligations to the Company or any of itsaffiliates under any Restrictive Covenant, then all Earned Shares subject to such Participant’s Performance Share Unit Award and earnedcash subject to a Performance Cash Unit shall become fully vested as of the effective date of the Participant’s termination of employmentor date of death, as the case may be. To the extent the Award has not been earned as of the date of the Participant’s termination ofemployment or death (i.e. as to which the current Performance Cycle has not elapsed), the Participant shall become 5Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. vested in a pro-rated Award based on the number of elapsed days in the current Performance Cycle as of the termination date (or fullyvested with respect to such an Award for 2012 upon an involuntary termination without Cause) and the extent to which the Companyperformance goals established under the Program for such Performance Cycle are attained as of the last day of the year in which thetermination date occurs (and assuming a 100% individual performance multiplier), and such Award shall be payable as of the date thefirst third of the Awards for such Performance Cycle are payable to Participants who remain actively employed with the Company. (ii)Retirement, Disability, Death or Involuntary Termination Without Cause – Awards Granted on or after January 1, 2013 (IncludingTransition Awards). If a Participant’s employment with the Company terminates by reason of Retirement, Disability, death or aninvoluntary termination of employment by the Company for a reason other than Cause, and such Participant has not breached his or herobligations to the Company or any of its affiliates under any Restrictive Covenant, then (A) if such event occurs within the first 12months of the Performance Cycle, then the Participant shall earn and become vested in a pro-rated Award (both First and SecondTranches, in the case of Bridge Awards) based on the number of elapsed days in such 12-month period as of the termination date (pro-ration determined by dividing the number of elapsed days by 365) and the extent to which the performance goals established under theProgram for such Performance Cycle (or portion thereof, in the case of the Transition Awards) are attained, and (B) if such event occursafter the first 12 months of the Performance Cycle, then the Participant shall become fully vested in all Earned Shares (the numberdetermined in accordance with Section 3(b) above) or earned cash, as applicable. In either event, the Earned Shares or cash shall bepayable on the next payout date applicable to Participants who remain actively employed with the Company (either the payout date forthe First Tranche or Second Tranche, as applicable, in the case of Transition Awards). (iii)Termination for Other Reasons. If a Participant’s employment with the Company terminates for any reason other than as described inclause (i) or (ii) of this Section 3(f) or if the Participant has breached his or her obligations to the Company or any of its affiliates underany Restrictive Covenant, the unvested portion of such Participant’s Award shall be forfeited and terminate as of the date of suchtermination of employment.(g) Restriction on Sale of Shares by Senior Officers. Shares of Common Stock issued under an Award pursuant to Section 3(e) to aParticipant who is employed as of the Grant Date in a position of, or more senior than, Senior Vice President may not be sold or transferred by suchParticipant until the earlier to occur of (i) the date as of which the final third of such Award is scheduled to become vested pursuant to Section 3(c)(even if such Award actually vests earlier pursuant to Section 3(f)) or (ii) the date of the Participant’s death, regardless of when such shares are issued ortransferred to such Participant. Effective January 1, 2013, this provision shall no longer be effective. 6Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(h) Awards Granted to Employees of Commonwealth Edison Company Prior to 2014. If Performance Share Unit Awards are granted toParticipants who are employed by Commonwealth Edison Company, an Illinois corporation and subsidiary of the Company (“ComEd”), then unlessthe Committee determines otherwise, (i) the number of such Participant’s Earned Shares shall be determined based on the achievement of performancecriteria established by the Board of Directors of ComEd and ratified by the Committee, subject to the maximum number of Earned Shares that may besubject to a Performance Share Unit Award, as set forth in Section 3(b), and (ii) such Performance Share Unit Awards for 2011 shall be settled (subject tothe vesting and other conditions herein) in a cash payment made by ComEd to the Participant in an amount equal to the Fair Market Value of thenumber of such Participant’s Earned Shares, determined as of the applicable vesting date.4. Restricted Stock Unit Award Program.(a) Granting of Awards. The Committee may grant Restricted Stock Unit Awards to employees who are employed (i) in a Vice President orother executive position (including without limitation Nuclear Plant Managers) below the Senior Vice President level, and (ii) key managers and otherselect management employees, in each case as selected by the Committee in its sole discretion.(b) Terms of Awards. Awards shall be subject to the following terms and conditions and shall contain such additional terms andconditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set forth in the applicable Award Notice.(c) Number of Shares and Other Terms. The number of shares of Common Stock subject to a Restricted Stock Unit Award shall bedetermined by the Committee and set forth in the applicable Award Notice.(d) Vesting and Forfeiture. Except to the extent a Restricted Stock Unit Award becomes immediately vested upon a termination of theParticipant’s employment pursuant to Section 4(g) of the Program, the shares subject to a Restricted Stock Unit Award shall become vested (i) on thedate of the first regular meeting of the Committee in the calendar year following the calendar year in which the Grant Date occurs with respect to one-third of the number of shares of Common Stock subject to the Award on the Grant Date, (ii) on the date of the first regular meeting of the Committee inthe second calendar year following the calendar year in which the Grant Date occurs with respect to an additional one-third of the number of shares ofCommon Stock subject to the Award on the Grant Date, and (iii) on the date of the first regular meeting of the Committee in the third calendar yearfollowing the calendar year in which the Grant Date occurs with respect to the remaining shares of Common Stock subject to the Award on the GrantDate (but, with respect to each such year, not later than March 15), in each case subject to the Participant’s continuous employment with the Companythrough the applicable vesting date. 7Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(e) Dividend Equivalents. As of each Dividend Payment Date, the number of shares of Common Stock that are subject to a Restricted StockUnit Award shall be increased by (i) the product of the total number of shares of Common Stock that are subject to such Restricted Stock Unit Awardimmediately prior to the record date for such Dividend Payment Date, but that have not been issued pursuant to Section 4(f) as of such record date,multiplied by the dollar amount of the cash dividend paid per share of Common Stock, divided by (ii) the Fair Market Value of a share of CommonStock on such Dividend Payment Date. Such additional Restricted Stock Units shall be subject to all of the terms and conditions of the Award,including the vesting conditions set forth in Section 4(d).(f) Settlement of Vested Awards. Subject to the withholding of taxes pursuant to Section 8 of the Program, within 30 days after the vestingof a Restricted Stock Unit Award, in whole or in part (or at such later time as may be required pursuant to this Section 4(f)), the Company shall issue ortransfer to the Participant the number of shares of Common Stock that have become vested. The Company may effect such transfer either by thedelivery of one or more certificates of Common Stock to the Participant or by an appropriate entry on the books of the Company or of a dulyauthorized transfer agent of the Company, and in either case by issuing such shares in the Participant’s name or in such other name as is acceptable tothe Company and designated in writing by the Participant. The Company shall pay all original issue or transfer taxes and all fees and expenses incidentto such delivery, except as otherwise provided in Section 8 of the Program. Prior to the settlement of a Restricted Stock Unit Award, the holder of suchAward shall have no rights as a stockholder of the Company with respect to the shares of Common Stock subject to such Award. Notwithstanding theforegoing, if a Participant is a “Specified Employee,” within the meaning of section 409A of the Code, and such Participant is or will become eligiblefor Retirement prior to the calendar year in which the Restricted Stock Unit Award is scheduled to become fully vested, then any shares of CommonStock subject to the Award which become vested upon the Participant’s termination of employment in accordance with Section 4(g) of this Programshall be issued to the Participant as of the earlier to occur of the six-month anniversary of such Participant’s separation from service or the date of theParticipant’s death.(g) Termination of Employment. Except as otherwise provided in this Program or the Plan: (i)Retirement, Disability or Death. If a Participant’s employment with the Company terminates by reason of Retirement, Disability or death,and such Participant has not breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, thenall shares of Common Stock subject to such Participant’s Restricted Stock Unit Award shall become fully vested as of the effective dateof the Participant’s termination of employment or date of death, as the case may be. (ii)Termination for Other Reasons. If a Participant’s employment with the Company terminates for any reason other than as described inclause (i) of this Section 4(g) or if the Participant has breached his or her obligations to the Company or any of its affiliates under anyRestrictive Covenant, the 8Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. unvested portion of such Participant’s Restricted Stock Unit Award shall be forfeited and terminate as of the date of such termination ofemployment; provided however, that such an Award granted on or after January 1, 2012 shall become fully vested upon an involuntarytermination without Cause.5. Stock Option Award Program.(a) Granting of Awards. The Committee may grant Option Awards to employees who are employed in a Senior Vice President or moresenior position, as selected by the Committee in its sole discretion or, to the extent permitted by the Plan, the Chief Executive Officer of the Company.(b) Terms of Awards. Awards shall be subject to the following terms and conditions and shall contain such additional terms andconditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set forth in the applicable Award Notice.(c) Number of Shares. The number of shares of Common Stock subject to an Option Award shall be determined by the Committee and setforth in the applicable Award Notice.(d) Term of Option. Except to the extent earlier terminated or exercised, each Option shall expire on, and in no event may any portion ofsuch Option be exercised after, the tenth anniversary of the Grant Date (the “Expiration Date”).(e) Vesting and Forfeiture. Except to the extent the Award becomes immediately vested upon a termination of the Participant’s employmentpursuant to Section 5(g) of the Program, the Option shall become vested and exercisable (i) on the first anniversary of the Grant Date with respect to one-fourth of the number of shares of Common Stock subject to the Award on the Grant Date, (ii) on the second anniversary of the Grant Date with respect to anadditional one-fourth of the number of shares of Common Stock subject to the Award on the Grant Date (iii) on the third anniversary of the Grant Date withrespect to an additional one-fourth of the number of shares of Common Stock subject to the Award on the Grant Date, and (iv) on the fourth anniversary of theGrant Date with respect to the remaining shares of Common Stock subject to the award on the Grant Date, in each case subject to the Participant’s continuousemployment with the Company through the applicable vesting date.(f) Method of Exercise. To the extent permitted by the Administrator, a Participant may exercise an Option (i) by giving written notice to theCompany (or its designated agent) specifying the number of whole shares of Common Stock to be purchased and accompanying such notice with paymenttherefor in full, and without any extension of credit, either (A) in cash, (B) by delivery (either actual delivery or by attestation procedures established by theCompany) to the Company of previously owned whole shares of Common Stock having a Fair Market Value, determined as of the date of exercise, equal tothe aggregate purchase price payable by reason of such exercise, (C) authorizing the Company to withhold whole shares of Common Stock which 9Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.would otherwise be delivered having an aggregate Fair Market Value, determined as of the date of exercise, equal to the amount necessary to satisfy suchobligation, provided that the Committee determines that such withholding of shares does not cause the Company to recognize an increased compensationexpense under applicable accounting principles, (D) except as may be prohibited by applicable law, in cash by a broker-dealer acceptable to the Company towhom the Participant has submitted an irrevocable notice of exercise or (E) a combination of (A), (B) and (C) and (ii) by executing such documents as theCompany may reasonably request. Any fraction of a share of Common Stock which would be required to pay such purchase price shall be disregarded and theremaining amount due shall be paid in cash by the Participant. No shares of Common Stock shall be issued and no certificate representing Common Stockshall be delivered until the full purchase price therefor and any withholding taxes thereon, as described in Section 8, have been paid.(g) Termination of Employment. (i)Retirement or Disability. If the Company ceases to employ a Participant by reason of such Participant’s Retirement or Disability, eachOption held by such Participant shall be fully exercisable, and may thereafter be exercised by such Participant (or such Participant’s legalrepresentative or similar person) until and including the earlier to occur of (i) the fifth anniversary of the effective date of suchParticipant’s termination of employment and (ii) the Expiration Date. (ii)Death. If the Company ceases to employ a Participant by reason of such Participant’s death, each Option held by such Participant shall befully exercisable, and may thereafter be exercised by such Participant’s executor, administrator, legal representative, beneficiary orsimilar person until and including the earlier to occur of (i) the third anniversary of the date of death and (ii) the Expiration Date. (iii)Cause. If the Company ceases to employ a Participant due to a termination of employment by the Company for Cause, each Option heldby such Participant shall be cancelled and cease to be exercisable as of the earlier to occur of (i) the effective date of such termination ofemployment and (ii) the date on which the Participant first engaged in conduct giving rise to a termination for Cause, and the Companythereafter may require the repayment of any amounts received by such Participant in connection with an exercise of such Optionfollowing such cancellation date. (iv)Other Termination. Subject to clauses (v), (vi) and (vii) below, if the Company ceases to employ a Participant for any reason other than asdescribed in clause (i), (ii) or (iii) above, then each Option held by such Participant shall be exercisable only to the extent that suchOption is exercisable on the effective date of such Participant’s termination of employment, and may thereafter be exercised by suchParticipant (or such Participant’s legal representative or similar person) until and including the earlier to occur of (i) the date which is 90days after the effective date of such Participant’s termination of employment and (ii) the Expiration Date. 10Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. (v)Death Following Termination of Employment. If a Participant dies during the applicable post-termination exercise period described inclause (iv), each Option held by such Participant shall be exercisable only to the extent that such Option is exercisable on the date ofsuch Participant’s death and may thereafter be exercised by the Participant’s executor, administrator, legal representative, beneficiary orsimilar person until and including the earlier to occur of (i) the first anniversary of the date of death and (ii) the expiration date of theterm of such Option. (vi)Breach of Restrictive Covenant. Notwithstanding clauses (i) through (v), if a Participant breaches his or her obligations to the Companyor any of its affiliates under a Restrictive Covenant, each Option held by such Participant shall be cancelled and cease to be exercisableas of the date on which the Participant first breached such Restrictive Covenant, and the Company thereafter may require the repaymentof any amounts received by such Participant in connection with an exercise of such Option following such cancellation date. (vii)Certain Terminations After Change in Control. Unless otherwise specified in, and subject to all conditions set forth in, any individualchange in control agreement or severance plan, and notwithstanding any other provision of this Section 5(g), if within 24 monthsfollowing a Change in Control, the Company ceases to employ a Participant due to a termination of employment (i) by the Companyother than for Cause, or (ii) with respect to a Participant whose position is at grade level E09 (or its equivalent), by the Participant forGood Reason, such Participant’s outstanding Options shall immediately become fully exercisable and may thereafter be exercised bysuch Participant (or such Participant’s legal representative or similar person) until and including the earlier to occur of (A) the fifthanniversary of the effective date of such Participant’s termination of employment and (B) the Expiration Date.(h) Termination of Option. In no event may an Option be exercised after it terminates as set forth in this Section 5(h). An Option shall terminate,to the extent not earlier exercised or terminated pursuant to Section 5(g), on the Expiration Date. Upon the termination of the Option, the Option and allrights thereunder shall immediately become null and void.6. Employment. For purposes of this Program, references to employment with the Company shall include (i) employment with an Affiliate of theCompany and (ii) any period during which the Participant is on a leave of absence approved by the Company.7. Limited Transferability of Awards. Except as may otherwise be expressly provided in an Award Notice, an Award may be transferred by theParticipant only (1) by will, (2) the laws of descent and distribution or (3) pursuant to beneficiary designation procedures approved by the Company. Exceptto the extent permitted by the foregoing, an Award may not be sold, transferred, assigned, pledged, hypothecated, encumbered or otherwise disposed of(whether by operation of law or otherwise) or be subject to execution, attachment or similar process or domestic relations order. Upon any attempt so to sell,transfer, assign, pledge, hypothecate, encumber or otherwise dispose of an Award, such Award and all rights thereunder shall immediately become null andvoid. 11Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.8. Withholding Taxes. The Company shall have the right to require, prior to the issuance or delivery of any shares of Common Stock or thepayment of any cash pursuant to an Award, or upon the vesting of any Award that is considered deferred compensation, payment by the Participant of anyfederal, state, local or other taxes which may be required to be withheld or paid in connection with such Award. The Company may withhold whole shares ofCommon Stock which would otherwise be delivered to a Participant, having an aggregate Fair Market Value determined as of the Tax Date, or withhold anamount of cash which would otherwise be payable to a Participant, in the amount necessary to satisfy any such obligation. The Participant may elect tosatisfy any such obligation by any of the following means, to the extent permitted by the Administrator: (A) a cash payment to the Company, (B) authorizingthe Company to withhold whole shares of Common Stock which would otherwise be delivered having an aggregate Fair Market Value, determined as of theTax Date, or withhold an amount of cash which would otherwise be payable to the Participant, equal to the amount necessary to satisfy any such obligation,(C) in the case of the exercise of an Option and except as may be prohibited by applicable law, a cash payment by a broker-dealer acceptable to the Companyto whom the Participant has submitted an irrevocable notice of exercise or (D) any combination of (A) and (B). Shares of Common Stock to be delivered orwithheld may not have an aggregate Fair Market Value in excess of the amount determined by applying the minimum statutory withholding rate. Anyfraction of a share of Common Stock which would be required to satisfy such an obligation shall be disregarded and the remaining amount due shall be paidin cash by the Participant.9. Adjustment. The number and class of securities subject to an Award shall be subject to adjustment as provided in Section 5.7 of the Plan. Thedecision of the Committee regarding any such adjustment shall be final, binding and conclusive.10. Compliance with Applicable Law. Each Award is subject to the condition that if the listing, registration or qualification of the shares subjectto such Award upon any securities exchange or under any law, or the consent or approval of any governmental body, or the taking of any other action isnecessary or desirable as a condition of, or in connection with, the delivery of shares hereunder, such Award may not be settled, in whole or in part, unlesssuch listing, registration, qualification, consent or approval shall have been effected or obtained, free of any conditions not acceptable to the Company.11. Award Subject to the Plan and Claw-back Policy. Each Award is subject to the provisions of the Plan, and each Award and this Program shallbe interpreted in accordance therewith. Notwithstanding any provision of the Program to the contrary, each Award shall be subject to a clawback pursuant tothe Exelon Executive Officer Compensation Recoupment Policy contained in the Exelon Corporation Board of Directors Corporate Governance Principles,as in effect from time to time, including any amendments thereto or new clawback policies required under the Dodd-Frank Wall Street Reform and ConsumerProtection Act and implementing applicable stock exchange listing standards or rules and regulations thereunder, or as otherwise required by law orregulation. 12Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.12. Investment Representation. By accepting an Award, the Participant represents and covenants that (a) any share of Common Stock acquiredupon the vesting of the Award will be acquired for investment and not with a view to the distribution thereof within the meaning of the Securities Act of1933, as amended (the “Securities Act”), unless such acquisition has been registered under the Securities Act and any applicable state securities law; (b) anysubsequent sale of any such shares shall be made either pursuant to an effective registration statement under the Securities Act and any applicable statesecurities laws, or pursuant to an exemption from registration under the Securities Act and such state securities laws; and (c) if requested by the Company, theParticipant shall submit a written statement, in form satisfactory to the Company, to the effect that such representation (x) is true and correct as of the date ofacquisition of any shares hereunder or (y) is true and correct as of the date of any sale of any such shares, as applicable. As a further condition precedent to thedelivery to the Participant of any shares subject to the Award, the Participant shall comply with all regulations and requirements of any regulatory authorityhaving control of or supervision over the issuance of the shares and, in connection therewith, shall execute any documents which the Company shall in itssole discretion deem necessary or advisable.13. Award Confers No Rights to Continued Employment. In no event shall the granting of an Award or its acceptance by a Participant give or bedeemed to give the Participant any right to continued employment by the Company.14. Administrator. This Program shall be administered by the Company’s Vice President, Corporate Compensation (the “Administrator”). Exceptfor authority reserved to the Board or the Committee, the Administrator shall have the right to interpret the Program, make any determinations hereunder, andtake any necessary or appropriate actions with respect to the administration of the Program or in connection with each Award. Any such interpretation,determination or other action made or taken by the regarding this Program or an Award shall be final, binding and conclusive.15. Miscellaneous Provisions.(a) Successors. This Program and each Award shall be binding upon and inure to the benefit of any successor or successors of the Companyand any person or persons who shall, upon the death of a Participant, acquire any rights under such Award in accordance with this Program or the Plan.(b) Notices. All notices, requests or other communications provided for in this Program (other than the exercise of a stock option) shall bemade, if to the Company, to Exelon Corporation, 10 South Dearborn Street, Chicago, Illinois 60603, Attention: Vice President, CorporateCompensation, and if to the Participant, to his or her then current work location. All notices, requests or other communications provided for in thisProgram shall be made in writing either (a) by personal delivery to the party entitled thereto, (b) by facsimile with confirmation of receipt, (c) bymailing in the United States mails to the last known address of the party entitled thereto or (d) by express courier service. The notice, request or othercommunication shall be deemed to be received upon personal delivery, upon confirmation of receipt of facsimile transmission, or upon receipt by theparty entitled thereto if by United States mail or express courier service; provided, however, that if a notice, request or other communication is notreceived during regular business hours, it shall be deemed to be received on the next succeeding business day of the Company. 13Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(c) Section 409A. This Program and the Awards granted hereunder are intended to comply with the requirements of section 409A of theCode and shall be interpreted and construed consistently with such intent. Awards granted pursuant to this Program are also intended to be exemptfrom Section 409A of the Code to the maximum extent possible as short-term deferrals pursuant to Treasury regulation §1.409A-1(b)(4), and for thispurpose each payment shall be considered a separate payment. In the event the terms of an Award would subject a Participant to taxes or penaltiesunder Section 409A of the Code (“409A Penalties”), the Company may modify the terms of such Award to avoid such 409A Penalties, to the extentpossible; provided that in no event shall the Company be responsible for any 409A Penalties that arise in connection with any Award. To the extentthe timing of payment under an Award is determined by reference to a Participant’s “termination of employment,” such term shall be deemed to refer tothe Participant’s “separation from service,” within the meaning of section 409A of the Code. Notwithstanding any other provision in this Program, if aParticipant is a “specified employee,” as defined in Section 409A of the Code, as of the date of such Participant’s separation from service, then to theextent any amount payable to the Participant (i) constitutes the payment of nonqualified deferred compensation, within the meaning of Section 409Aof the Code, (ii) is payable upon the Participant’s separation from service and (iii) under the terms of this Program would be payable prior to the six-month anniversary of the Participant’s separation from service, such payment shall be delayed until the earlier to occur of (A) the six-monthanniversary of the separation from service and (B) the date of the Participant’s death.(d) Amendment. The terms of this Program may be amended by the Committee or the Board (or their respective delegates), provided thatthe Chief Human Resources Officer or the Vice President, Corporate Compensation, of the Company may amend the Program to comply withapplicable law, to make administrative changes or to carry out directives of the Board or the Committee.(e) Governing Law. This Program and each Award granted thereunder, and all determinations made and actions taken pursuant thereto, tothe extent not governed by the laws of the United States, shall be governed by the laws of the Commonwealth of Pennsylvania and construed inaccordance therewith without giving effect to principles of conflicts of laws. 14Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.IN WITNESS WHEREOF, Exelon Corporation has caused this instrument to be executed by its Senior Vice President & Chief Human ResourcesOfficer, effective as of January 1, 2014. EXELON CORPORATIONBy: Senior Vice President & Chief Human Resources Officer 15Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 12.1Exelon CorporationRatio of Earnings to Fixed Charges Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 4,221 3,952 1,798 2,773 2,486 Plus: Loss from equity investees — 1 91 (10) 20 Less: Capitalized interest (43) (57) (75) (67) (79) Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest 4,178 3,896 1,814 2,696 2,427 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 836 761 1,021 1,436 1,110 Interest component of rental expense (a) 241 237 310 269 288 Total fixed charges 1,077 998 1,331 1,705 1,398 Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest plus fixed charges 5,255 4,894 3,145 4,401 3,825 Ratio of earnings to fixed charges 4.9 4.9 2.4 2.6 2.7 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.Exelon CorporationRatio of Earnings to Fixed Charges and Preferred Stock Dividends Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 4,221 3,952 1,798 2,773 2,486 Plus: Loss from equity investees — 1 91 (10) 20 Less: Capitalized interest (43) (57) (75) (67) (79) Preference security dividend requirements (7) (6) (26) (32) (18) Pre-tax income from continuing operations after adjustment for income or loss from equity investees,capitalized interest and preference security dividend requirements 4,171 3,890 1,788 2,664 2,409 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 836 761 1,021 1,436 1,110 Interest component of rental expense (a) 241 237 310 269 288 Preference security dividend requirements of consolidated subsidiaries 7 6 26 32 18 Total fixed charges 1,084 1,004 1,357 1,737 1,416 Pre-tax income from continuing operations after adjustment for income or loss from equity investees,capitalized interest and preference security dividend requirements plus fixed charges 5,255 4,894 3,145 4,401 3,825 Ratio of earnings to fixed charges and preferred stock dividends 4.8 4.9 2.3 2.5 2.7 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 12.2Exelon Generation Company, LLCRatio of Earnings to Fixed Charges Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 3,150 2,827 1,058 1,675 1,226 Plus: (Income) or loss from equity investees — 1 91 (10) 20 Less: Capitalized interest (38) (49) (67) (54) (63) Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest 3,112 2,779 1,082 1,611 1,183 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 191 219 402 445 396 Interest component of rental expense (a) 222 220 291 248 269 Total fixed charges 413 439 693 693 665 Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest plus fixed charges 3,525 3,218 1,775 2,304 1,848 Ratio of earnings to combined fixed charges 8.5 7.3 2.6 3.3 2.8 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 12.3Commonwealth Edison CompanyRatio of Earnings to Fixed Charges Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 693 666 618 401 676 Plus: Loss from equity investees — — — — — Less:Capitalized interest (2) (4) (3) (5) (2) Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalizedinterest 691 662 615 396 674 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 368 330 297 575 311 Interest component of rental expense (a) 6 6 6 5 5 Total fixed charges 374 336 303 580 316 Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalizedinterest plus fixed charges 1,065 998 918 976 990 Ratio of earnings to fixed charges 2.8 3.0 3.0 1.7 3.1 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 12.4PECO Energy CompanyRatio of Earnings to Fixed Charges Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 476 535 508 557 466 Plus: Loss from equity investees — — — — — Less: Capitalized interest (4) (4) (2) (2) (2) Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest 472 531 506 555 464 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 193 135 122 114 112 Interest component of rental expense (a) 10 9 9 7 5 Total fixed charges 203 144 131 121 117 Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest plus fixed charges 675 675 637 676 581 Ratio of earnings to combined fixed charges 3.3 4.7 4.9 5.6 5.0 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.PECO Energy CompanyRatio of Earnings to Fixed Charges and Preferred Stock Dividends Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 476 535 508 557 466 Plus: Loss from equity investees — — — — — Less: Capitalized interest (4) (4) (2) (2) (2) Preference security dividend requirements (6) (6) (5) (10) — Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalizedinterest and preference security dividend requirements 466 525 501 545 464 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 193 135 122 114 112 Interest component of rental expense (a) 10 9 9 7 5 Preference security dividend requirements 6 6 5 10 — Total fixed charges 209 150 136 131 117 Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalizedinterest and preference security dividend requirements plus fixed charges 675 675 637 676 581 Ratio of earnings to fixed charges and preferred stock dividends 3.2 4.5 4.6 5.2 5 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 12.5BGERatio of Earnings to Fixed Charges Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 244 211 11 344 351 Less: Capitalized interest (6) (7) (5) (6) (12) Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest 238 204 6 338 339 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 137 136 149 127 118 Interest component of rental expense (a) 4 5 4 4 4 Total fixed charges 141 141 153 131 122 Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalizedinterest and preference security dividend requirements plus fixed charges 379 345 159 469 461 Ratio of earnings to fixed charges 2.7 2.4 1.0 3.6 3.8 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.BGERatio of Earnings to Fixed Charges and Preference Stock Dividends Years Ended December 31, 2010 2011 2012 2013 2014 Pre-tax income from continuing operations 244 211 11 344 351 Less: Capitalized interest (6) (7) (5) (6) (12) Preference security dividend requirements (20) (20) (20) (21) (22) Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest 218 184 (14) 317 317 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 137 136 149 127 118 Interest component of rental expense (a) 4 5 4 4 4 Preference security dividend requirements 20 20 20 21 22 Total fixed charges 161 161 173 152 144 Pre-tax income from continuing operations after adjustment for income or loss from equity investees,capitalized interest and preference security dividend requirements plus fixed charges 379 345 159 469 461 Ratio of earnings to fixed charges and preferred stock dividends 2.4 2.1 0.9(b) 3.1 3.2 (a)Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.(b)The ratio coverage was less than 1:1. The registrant must generate additional earnings of $14 million to achieve a coverage ratio of 1:1.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 21.1Exelon Corporation Name Jurisdiction2014 ESA HoldCo, LLC Delaware2014 ESA Project Company, LLC DelawareA/C Fuels Company PennsylvaniaAgriWind LLC IllinoisAgriWind Project L.L.C. DelawareAlbany Green Energy, LLC GeorgiaAnnova LNG Common Infrastructure, LLC DelawareAnnova LNG, LLC DelawareAnnova LNG, LLC, Series A Units DelawareAnnova LNG, LLC, Series Z Units DelawareAPS Constellation, LLC DelawareAquion Energy, Inc. DelawareATNP Finance Company DelawareAV Solar Ranch 1, LLC DelawareBaltimore Gas and Electric Company MarylandBC Energy LLC MinnesotaBeebe 1B Renewable Energy, LLC DelawareBeebe Renewable Energy, LLC DelawareBennett Creek Windfarm, LLC IdahoBGE Capital Trust II DelawareBGE Home Products & Services, LLC DelawareBig Top, LLC OregonBlue Breezes II, L.L.C. MinnesotaBlue Breezes, L.L.C. MinnesotaBraidwood 1 NQF, LLC NevadaBraidwood 2 NQF, LLC NevadaBreezy Bucks-I LLC MinnesotaBreezy Bucks-II LLC MinnesotaButter Creek Power, LLC OregonByron 1 NQF, LLC NevadaByron 2 NQF, LLC NevadaC3, Inc. DelawareCalifornia PV Energy, LLC DelawareCalvert Cliffs Nuclear Power Plant, LLC MarylandCassia Gulch Wind Park LLC IdahoCassia Wind Farm LLC IdahoCD Panther I, Inc. MarylandCD Panther II, LLC DelawareCD Panther Partners, L.P. DelawareCD SEGS V, Inc. MarylandCD SEGS VI, Inc. MarylandCE Central Wayne Energy Recovery Limited Partnership MarylandCE Colver I, Inc. MarylandCE Colver II, LLC DelawareCE Colver III, Inc. MarylandCE Culm, Inc. MarylandCE FundingCo, LLC DelawareCE Nuclear, LLC DelawareCE Wayne I, Inc. MarylandCE Wayne II, Inc. MarylandCECG International Holdings, Inc. DelawareCentral Wayne Energy Recovery Limited Partnership MarylandCER Generation, LLC DelawareCER-Quail Run Energy LLC DelawareCER-Quail Run Energy Partners LP DelawareCEU Arkoma West, LLC DelawareCEU CHC, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. CEU CoLa, LLC DelawareCEU Development, LLC DelawareCEU Eagle Ford, LLC DelawareCEU East Fort Peck, LLC DelawareCEU Fayetteville, LLC DelawareCEU Floyd Shale, LLC DelawareCEU Holdings, LLC DelawareCEU Huntsville, LLC DelawareCEU Kingston, LLC DelawareCEU Offshore I, LLC DelawareCEU Ohio Shale, LLC DelawareCEU Paradigm, LLC DelawareCEU Pinedale, LLC DelawareCEU Plymouth, LLC DelawareCEU Simplicity, LLC DelawareCEU Trenton, LLC DelawareCEU W&D, LLC DelawareChargePoint Inc. DelawareChristoffer Wind Energy I LLC MinnesotaChristoffer Wind Energy II LLC MinnesotaChristoffer Wind Energy III LLC MinnesotaChristoffer Wind Energy IV LLC MinnesotaCII Solarpower I, Inc. MarylandCisco Wind Energy LLC MinnesotaClinton NQF, LLC NevadaCLT Energy Services Group, L.L.C. PennsylvaniaCNE Gas Holdings, LLC KentuckyCNE Gas Supply, LLC DelawareCNEG Holdings, LLC DelawareCNEGH Holdings, LLC DelawareCogenex Corporation MassachusettsCoLa Resources LLC DelawareColorado Bend I Power, LLC DelawareColorado Bend II Power, LLC DelawareColorado Bend Services, LLC DelawareComEd Financing III DelawareCommonwealth Edison Company IllinoisCommonwealth Edison Company of Indiana, Inc. IndianaCompass Energy Gas Services, LLC VirginiaCompass Energy Services, Inc. VirginiaConstellation Alliance II, LP TexasConstellation Alliance, LLC DelawareConstellation Bulk Energy Holdings, Inc. Marshall IslandsConstellation DCO Albany Power Holdings, LLC DelawareConstellation Energy Canada, Inc. OntarioConstellation Energy Commodities Group Limited United KingdomConstellation Energy Commodities Group Maine, LLC DelawareConstellation Energy Gas Choice, Inc. DelawareConstellation Energy Nuclear Group, LLC MarylandConstellation Energy Partners Holdings, LLC DelawareConstellation Energy Power Choice, Inc. DelawareConstellation Energy Projects & Services Group Advisors, LLC DelawareConstellation Energy Projects and Services Canada, Inc. FederalConstellation Energy Resources, LLC DelawareConstellation Energy Upstream Holdings, Inc. DelawareConstellation Holdings, LLC MarylandConstellation International Holdings, Inc. Marshall IslandsConstellation Mystic Power, LLC DelawareConstellation NewEnergy - Gas Division, LLC KentuckySource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Constellation NewEnergy Canada Inc.OntarioConstellation NewEnergy, Inc.DelawareConstellation Nuclear Power Plants, LLCDelawareConstellation Nuclear, LLCDelawareConstellation Operating ServicesCaliforniaConstellation Power Source Generation, LLCMarylandConstellation Power, Inc.MarylandConstellation Sacramento Holding, LLCDelawareConstellation Solar Arizona, LLCDelawareConstellation Solar California, LLCDelawareConstellation Solar Connecticut, LLCDelawareConstellation Solar DC, LLCDelawareConstellation Solar Federal, LLCDelawareConstellation Solar Georgia, LLCGeorgiaConstellation Solar Holding, LLCDelawareConstellation Solar Horizons Holding, LLCDelawareConstellation Solar Horizons, LLCDelawareConstellation Solar Maryland II, LLCDelawareConstellation Solar Maryland MC, LLCDelawareConstellation Solar Maryland, LLCDelawareConstellation Solar Massachusetts, LLCDelawareConstellation Solar Net Metering, LLCDelawareConstellation Solar New Jersey II, LLCDelawareConstellation Solar New Jersey III, LLCDelawareConstellation Solar New Jersey, LLCDelawareConstellation Solar New York, LLCDelawareConstellation Solar Ohio, LLCDelawareConstellation Solar, LLCDelawareContinental Wind Holding, LLCDelawareContinental Wind, LLCDelawareCool Planet Energy Systems, Inc.DelawareCOSI Central Wayne, Inc.MarylandCOSI Sunnyside, Inc.MarylandCOSI Ultra II, Inc.MarylandCOSI Ultra, Inc.MarylandCow Branch Wind Power, L.L.C.MissouriCP Sunnyside I, Inc.MarylandCP Windfarm, LLCMinnesotaCPower Holdings, LLCDelawareCR Clearing, LLCMissouriCriterion Power Partners, LLCDelawareDAJAW Transmission LLCMinnesotaDenver Airport Solar, LLCDelawareDresden 1 NQF, LLCNevadaDresden 2 NQF, LLCNevadaDresden 3 NQF, LLCNevadaeCurv Inc.DelawareEnergy Performance Services, Inc.PennsylvaniaEssess Inc.DelawareETT Canada, Inc.New BrunswickEwington Energy Systems LLCMinnesotaExelon AVSR Holding, LLCDelawareExelon AVSR, LLCDelawareExelon Business Services Company, LLCDelawareExelon Capital Trust IDelawareExelon Capital Trust IIDelawareExelon Capital Trust IIIDelawareExelon CorporationPennsylvaniaExelon Energy Delivery Company, LLCDelawareExelon Enterprises Company, LLCPennsylvaniaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exelon Framingham, LLCDelawareExelon Generation Acquisitions, LLCDelawareExelon Generation Company, LLCPennsylvaniaExelon Generation Consolidation, LLCNevadaExelon Generation Finance Company, LLCDelawareExelon Generation International, Inc.PennsylvaniaExelon Generation LimitedUnited KingdomExelon Mechanical, LLCDelawareExelon Microgrid, LLCDelawareExelon New Boston, LLCDelawareExelon New England Holdings, LLCDelawareExelon Nuclear Partners International S.a r.l.LuxembourgExelon Nuclear Partners, LLCDelawareExelon Nuclear Security, LLCDelawareExelon Peaker Development Limited, LLCDelawareExelon PowerLabs, LLCPennsylvaniaExelon Solar Chicago LLCDelawareExelon Transmission Company, LLCDelawareExelon West Medway II, LLCDelawareExelon West Medway, LLCDelawareExelon Wind 1, LLCTexasExelon Wind 10, LLCTexasExelon Wind 11, LLCTexasExelon Wind 2, LLCTexasExelon Wind 3, LLCTexasExelon Wind 4, LLCTexasExelon Wind 5, LLCTexasExelon Wind 6, LLCTexasExelon Wind 7, LLCTexasExelon Wind 8, LLCTexasExelon Wind 9, LLCTexasExelon Wind Canada Inc.CanadaExelon Wind, LLCDelawareExelon Wyman, LLCDelawareEx-FM, Inc.New YorkEx-FME, Inc.DelawareExGen Renewables I Holding, LLCDelawareExGen Renewables I, LLCDelawareExGen Texas II Power Holdings, LLCDelawareExGen Texas II Power, LLCDelawareExGen Texas Power Holdings, LLCDelawareExGen Texas Power Services, LLCDelawareExGen Texas Power, LLCDelawareExGen Ventures International Holdings II LimitedUnited KingdomExGen Ventures International Holdings LimitedUnited KingdomExTel Corporation, LLCDelawareF & M Holdings Company, L.L.C.DelawareFair Wind Power Partners, LLCDelawareFloDesignDelawareFour Corners Windfarm, LLCOregonFour Mile Canyon Windfarm, LLCOregonFourmile Wind Energy, LLCMarylandG-Flow Wind, LLCMinnesotaGrande Prairie Generation, Inc.AlbertaGreen Acres Breeze, LLCMinnesotaGreensburg Wind Farm, LLCDelawareHandley Power, LLCDelawareHandsome Lake Energy, LLCMarylandHarvest II Windfarm, LLCDelawareHarvest Windfarm, LLCMichiganSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.High Mesa Energy, LLCIdahoHigh Plains Wind Power, LLCTexasHolyoke Solar, LLCDelawareHot Springs Windfarm, LLCIdahoIntegrys Energy Services - Electric, LLCDelawareIntegrys Energy Services - Natural Gas, LLCDelawareIntegrys Energy Services of New York, Inc.New YorkIntegrys Energy Services, Inc.WisconsinK & D Energy LLCMinnesotaKC Energy LLCMinnesotaKSS Turbines LLCMinnesotaLa Salle 1 NQF, LLCNevadaLa Salle 2 NQF, LLCNevadaLaPorte Power, LLCDelawareLas Vegas District Energy, LLCDelawareLimerick 1 NQF, LLCNevadaLimerick 2 NQF, LLCNevadaLoess Hills Wind Farm, LLCMissouriLuz Solar Partners Ltd., IVCaliforniaLuz Solar Partners Ltd., VCaliforniaLuz Solar Partners Ltd., VICaliforniaMarshall Wind 1, LLCMinnesotaMarshall Wind 2, LLCMinnesotaMarshall Wind 3, LLCMinnesotaMarshall Wind 4, LLCMinnesotaMarshall Wind 5, LLCMinnesotaMarshall Wind 6, LLCMinnesotaMichigan Wind 1, LLCDelawareMichigan Wind 2, LLCDelawareMichigan Wind 3, LLCDelawareMinnesota Breeze, LLCMinnesotaMohave Sunrise Solar I, LLCArizonaMountain Creek Power, LLCDelawareMountain Top Wind Power, LLCMarylandMXENERGY (CANADA) LTD.Nova ScotiaMxEnergy Holdings Inc.DelawareNine Mile Point Nuclear Station, LLCDelawareNorth Shore District Energy, LLCDelawareNorthwind Thermal Technologies Canada Inc.New BrunswickOgin Inc.DelawareOMF 11520, LLCDelawareOregon Trail Windfarm, LLCOregonOutback Solar, LLCOregonOyster Creek NQF, LLCNevadaPacific Canyon Windfarm, LLCOregonPanther Creek Holdings, Inc.DelawarePanther Creek PartnersDelawarePeach Bottom 1 NQF, LLCNevadaPeach Bottom 2 NQF, LLCNevadaPeach Bottom 3 NQF, LLCNevadaPEC Financial Services, LLCPennsylvaniaPECO Energy Capital Corp.DelawarePECO Energy Capital Trust IIIDelawarePECO Energy Capital Trust IVDelawarePECO Energy Capital Trust VDelawarePECO Energy Capital Trust VIDelawarePECO Energy Capital, L.P.DelawarePECO Energy CompanyPennsylvaniaPECO Wireless, LLCDelawarePegasus Power Company, Inc.CaliforniaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Pegasus Power Partners, a California Limited PartnershipCaliforniaPinedale Energy, LLCColoradoPoseidon Interconnect, LLCDelawarePowerhouse Dynamics Inc.DelawarePrairie Wind Power LLCMinnesotaProterra Inc.DelawarePurple Acquisition Corp.DelawareQuad Cities 1 NQF, LLCNevadaQuad Cities 2 NQF, LLCNevadaR.E. Ginna Nuclear Power Plant, LLCMarylandResidential Solar Holding, LLCDelawareResidential Solar II, LLCDelawareRF HoldCo LLCDelawareRITELine Illinois, LLCIllinoisRITELine Indiana, LLCIndianaRITELine Transmission Development, LLCDelawareRoadrunner-I LLCMinnesotaRSB BondCo LLCDelawareSacramento PV Energy, LLCDelawareSalem 1 NQF, LLCNevadaSalem 2 NQF, LLCNevadaSalty Dog-I LLCMinnesotaSalty Dog-II LLCMinnesotaSand Ranch Windfarm, LLCOregonScherer Holdings 1, LLCDelawareScherer Holdings 2, LLCDelawareScherer Holdings 3, LLCDelawareSendero Wind Energy, LLCDelawareShane’s Wind Machine LLCMinnesotaShooting Star Wind Project, LLCDelawareSimmons & Eastern, LLCDelawareSolarbridge Technologies Inc.DelawareStar Electricity, Inc.TexasSunnyside Cogeneration AssociatesUtahSunnyside Generation, LLCDelawareSunnyside II, Inc.DelawareSunnyside II, L.P.DelawareSunnyside III, Inc.DelawareSunnyside Properties, LLCUtahSunset Breeze, LLCMinnesotaThreemile Canyon Wind I, LLCOregonTitan STC, LLCDelawareTMI NQF, LLCNevadaTuana Springs Energy, LLCIdahoUII, LLCIllinoisW&D Gas Partners, LLCDelawareWagon Trail, LLCOregonWally’s Wind Farm LLCMinnesotaWansley Holdings 1, LLCDelawareWansley Holdings 2, LLCDelawareWard Butte Windfarm, LLCOregonWater & Energy Savings Company, LLCDelawareWhitetail Wind Energy, LLCDelawareWildcat Finance, LLCDelawareWildcat Wind LLCNew MexicoWind Capital Holdings, LLCMissouriWindy Dog-1 LLCMinnesotaWolf Hollow I Power, LLCDelawareWolf Hollow II Power, LLCDelawareWolf Hollow Services, LLCDelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Wolf Wind Enterprises, LLCMinnesotaWolf Wind Transmission, LLCMinnesotaZion 1 NQF, LLCNevadaZion 2 NQF, LLCNevadaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 21.2Exelon Generation Company, LLC Name Jurisdiction2014 ESA HoldCo, LLC Delaware2014 ESA Project Company, LLC DelawareA/C Fuels Company PennsylvaniaAgriWind LLC IllinoisAgriWind Project L.L.C. DelawareAlbany Green Energy, LLC GeorgiaAnnova LNG Common Infrastructure, LLC DelawareAnnova LNG, LLC DelawareAnnova LNG, LLC, Series A Units DelawareAnnova LNG, LLC, Series Z Units DelawareAPS Constellation, LLC DelawareAquion Energy, Inc. DelawareAV Solar Ranch 1, LLC DelawareBC Energy LLC MinnesotaBeebe 1B Renewable Energy, LLC DelawareBeebe Renewable Energy, LLC DelawareBennett Creek Windfarm, LLC IdahoBGE Home Products & Services, LLC DelawareBig Top, LLC OregonBlue Breezes II, L.L.C. MinnesotaBlue Breezes, L.L.C. MinnesotaBraidwood 1 NQF, LLC NevadaBraidwood 2 NQF, LLC NevadaBreezy Bucks-I LLC MinnesotaBreezy Bucks-II LLC MinnesotaButter Creek Power, LLC OregonByron 1 NQF, LLC NevadaByron 2 NQF, LLC NevadaC3, Inc. DelawareCalifornia PV Energy, LLC DelawareCalvert Cliffs Nuclear Power Plant, LLC MarylandCassia Gulch Wind Park LLC IdahoCassia Wind Farm LLC IdahoCD Panther I, Inc. MarylandCD Panther II, LLC DelawareCD Panther Partners, L.P. DelawareCD SEGS V, Inc. MarylandCD SEGS VI, Inc. MarylandCE Central Wayne Energy Recovery Limited Partnership MarylandCE Colver I, Inc. MarylandCE Colver II, LLC DelawareCE Colver III, Inc. MarylandCE Culm, Inc. MarylandCE FundingCo, LLC DelawareCE Nuclear, LLC DelawareCE Wayne I, Inc. MarylandCE Wayne II, Inc. MarylandCECG International Holdings, Inc. DelawareCentral Wayne Energy Recovery Limited Partnership MarylandCER Generation, LLC DelawareCER-Quail Run Energy LLC DelawareCER-Quail Run Energy Partners LP DelawareCEU Arkoma West, LLC DelawareCEU CHC, LLC DelawareCEU CoLa, LLC DelawareCEU Development, LLC DelawareCEU Eagle Ford, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.CEU East Fort Peck, LLCDelawareCEU Fayetteville, LLCDelawareCEU Floyd Shale, LLCDelawareCEU Holdings, LLCDelawareCEU Huntsville, LLCDelawareCEU Kingston, LLCDelawareCEU Offshore I, LLCDelawareCEU Ohio Shale, LLCDelawareCEU Paradigm, LLCDelawareCEU Pinedale, LLCDelawareCEU Plymouth, LLCDelawareCEU Simplicity, LLCDelawareCEU Trenton, LLCDelawareCEU W&D, LLCDelawareChargePoint Inc.DelawareChristoffer Wind Energy I LLCMinnesotaChristoffer Wind Energy II LLCMinnesotaChristoffer Wind Energy III LLCMinnesotaChristoffer Wind Energy IV LLCMinnesotaCII Solarpower I, Inc.MarylandCisco Wind Energy LLCMinnesotaClinton NQF, LLCNevadaCLT Energy Services Group, L.L.C.PennsylvaniaCNE Gas Holdings, LLCKentuckyCNE Gas Supply, LLCDelawareCNEG Holdings, LLCDelawareCNEGH Holdings, LLCDelawareCogenex CorporationMassachusettsCoLa Resources LLCDelawareColorado Bend I Power, LLCDelawareColorado Bend II Power, LLCDelawareColorado Bend Services, LLCDelawareCompass Energy Gas Services, LLCVirginiaCompass Energy Services, Inc.VirginiaConstellation Alliance II, LPTexasConstellation Alliance, LLCDelawareConstellation Bulk Energy Holdings, Inc.Marshall IslandsConstellation DCO Albany Power Holdings, LLCDelawareConstellation Energy Canada, Inc.OntarioConstellation Energy Commodities Group LimitedUnited KingdomConstellation Energy Commodities Group Maine, LLCDelawareConstellation Energy Gas Choice, Inc.DelawareConstellation Energy Nuclear Group, LLCMarylandConstellation Energy Partners Holdings, LLCDelawareConstellation Energy Power Choice, Inc.DelawareConstellation Energy Projects & Services Group Advisors, LLCDelawareConstellation Energy Projects and Services Canada, Inc.FederalConstellation Energy Resources, LLCDelawareConstellation Energy Upstream Holdings, Inc.DelawareConstellation Holdings, LLCMarylandConstellation International Holdings, Inc.Marshall IslandsConstellation Mystic Power, LLCDelawareConstellation NewEnergy - Gas Division, LLCKentuckyConstellation NewEnergy Canada Inc.OntarioConstellation NewEnergy, Inc.DelawareConstellation Nuclear Power Plants, LLCDelawareConstellation Nuclear, LLCDelawareConstellation Operating ServicesCaliforniaConstellation Power Source Generation, LLCMarylandSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Constellation Power, Inc.MarylandConstellation Sacramento Holding, LLCDelawareConstellation Solar Arizona, LLCDelawareConstellation Solar California, LLCDelawareConstellation Solar Connecticut, LLCDelawareConstellation Solar DC, LLCDelawareConstellation Solar Federal, LLCDelawareConstellation Solar Georgia, LLCGeorgiaConstellation Solar Holding, LLCDelawareConstellation Solar Horizons Holding, LLCDelawareConstellation Solar Horizons, LLCDelawareConstellation Solar Maryland II, LLCDelawareConstellation Solar Maryland MC, LLCDelawareConstellation Solar Maryland, LLCDelawareConstellation Solar Massachusetts, LLCDelawareConstellation Solar Net Metering, LLCDelawareConstellation Solar New Jersey II, LLCDelawareConstellation Solar New Jersey III, LLCDelawareConstellation Solar New Jersey, LLCDelawareConstellation Solar New York, LLCDelawareConstellation Solar Ohio, LLCDelawareConstellation Solar, LLCDelawareContinental Wind Holding, LLCDelawareContinental Wind, LLCDelawareCool Planet Energy Systems, Inc.DelawareCOSI Central Wayne, Inc.MarylandCOSI Sunnyside, Inc.MarylandCOSI Ultra II, Inc.MarylandCOSI Ultra, Inc.MarylandCow Branch Wind Power, L.L.C.MissouriCP Sunnyside I, Inc.MarylandCP Windfarm, LLCMinnesotaCPower Holdings, LLCDelawareCR Clearing, LLCMissouriCriterion Power Partners, LLCDelawareDAJAW Transmission LLCMinnesotaDenver Airport Solar, LLCDelawareDresden 1 NQF, LLCNevadaDresden 2 NQF, LLCNevadaDresden 3 NQF, LLCNevadaeCurv Inc.DelawareEnergy Performance Services, Inc.PennsylvaniaEssess Inc.DelawareEwington Energy Systems LLCMinnesotaExelon AVSR Holding, LLCDelawareExelon AVSR, LLCDelawareExelon Framingham, LLCDelawareExelon Generation Acquisitions, LLCDelawareExelon Generation Consolidation, LLCNevadaExelon Generation Finance Company, LLCDelawareExelon Generation International, Inc.PennsylvaniaExelon Generation LimitedUnited KingdomExelon New Boston, LLCDelawareExelon New England Holdings, LLCDelawareExelon Nuclear Partners International S.a r.l.LuxembourgExelon Nuclear Partners, LLCDelawareExelon Nuclear Security, LLCDelawareExelon Peaker Development Limited, LLCDelawareExelon PowerLabs, LLCPennsylvaniaExelon Solar Chicago LLCDelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exelon West Medway II, LLCDelawareExelon West Medway, LLCDelawareExelon Wind 1, LLCTexasExelon Wind 10, LLCTexasExelon Wind 11, LLCTexasExelon Wind 2, LLCTexasExelon Wind 3, LLCTexasExelon Wind 4, LLCTexasExelon Wind 5, LLCTexasExelon Wind 6, LLCTexasExelon Wind 7, LLCTexasExelon Wind 8, LLCTexasExelon Wind 9, LLCTexasExelon Wind Canada Inc.CanadaExelon Wind, LLCDelawareExelon Wyman, LLCDelawareExGen Renewables I Holding, LLCDelawareExGen Renewables I, LLCDelawareExGen Texas II Power Holdings, LLCDelawareExGen Texas II Power, LLCDelawareExGen Texas Power Holdings, LLCDelawareExGen Texas Power Services, LLCDelawareExGen Texas Power, LLCDelawareExGen Ventures International Holdings II LimitedUnited KingdomExGen Ventures International Holdings LimitedUnited KingdomFair Wind Power Partners, LLCDelawareFloDesignDelawareFour Corners Windfarm, LLCOregonFour Mile Canyon Windfarm, LLCOregonFourmile Wind Energy, LLCMarylandG-Flow Wind, LLCMinnesotaGrande Prairie Generation, Inc.AlbertaGreen Acres Breeze, LLCMinnesotaGreensburg Wind Farm, LLCDelawareHandley Power, LLCDelawareHandsome Lake Energy, LLCMarylandHarvest II Windfarm, LLCDelawareHarvest Windfarm, LLCMichiganHigh Mesa Energy, LLCIdahoHigh Plains Wind Power, LLCTexasHolyoke Solar, LLCDelawareHot Springs Windfarm, LLCIdahoIntegrys Energy Services - Electric, LLCDelawareIntegrys Energy Services - Natural Gas, LLCDelawareIntegrys Energy Services of New York, Inc.New YorkIntegrys Energy Services, Inc.WisconsinK & D Energy LLCMinnesotaKC Energy LLCMinnesotaKSS Turbines LLCMinnesotaLa Salle 1 NQF, LLCNevadaLa Salle 2 NQF, LLCNevadaLaPorte Power, LLCDelawareLas Vegas District Energy, LLCDelawareLimerick 1 NQF, LLCNevadaLimerick 2 NQF, LLCNevadaLoess Hills Wind Farm, LLCMissouriLuz Solar Partners Ltd., IVCaliforniaLuz Solar Partners Ltd., VCaliforniaLuz Solar Partners Ltd., VICaliforniaMarshall Wind 1, LLCMinnesotaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Marshall Wind 2, LLCMinnesotaMarshall Wind 3, LLCMinnesotaMarshall Wind 4, LLCMinnesotaMarshall Wind 5, LLCMinnesotaMarshall Wind 6, LLCMinnesotaMichigan Wind 1, LLCDelawareMichigan Wind 2, LLCDelawareMichigan Wind 3, LLCDelawareMinnesota Breeze, LLCMinnesotaMohave Sunrise Solar I, LLCArizonaMountain Creek Power, LLCDelawareMountain Top Wind Power, LLCMarylandMXENERGY (CANADA) LTD.Nova ScotiaMxEnergy Holdings Inc.DelawareNine Mile Point Nuclear Station, LLCDelawareNorth Shore District Energy, LLCDelawareOgin Inc.DelawareOregon Trail Windfarm, LLCOregonOutback Solar, LLCOregonOyster Creek NQF, LLCNevadaPacific Canyon Windfarm, LLCOregonPanther Creek Holdings, Inc.DelawarePanther Creek PartnersDelawarePeach Bottom 1 NQF, LLCNevadaPeach Bottom 2 NQF, LLCNevadaPeach Bottom 3 NQF, LLCNevadaPegasus Power Company, Inc.CaliforniaPegasus Power Partners, a California Limited PartnershipCaliforniaPinedale Energy, LLCColoradoPoseidon Interconnect, LLCDelawarePowerhouse Dynamics Inc.DelawarePrairie Wind Power LLCMinnesotaProterra Inc.DelawareQuad Cities 1 NQF, LLCNevadaQuad Cities 2 NQF, LLCNevadaR.E. Ginna Nuclear Power Plant, LLCMarylandResidential Solar Holding, LLCDelawareResidential Solar II, LLCDelawareRoadrunner-I LLCMinnesotaSacramento PV Energy, LLCDelawareSalem 1 NQF, LLCNevadaSalem 2 NQF, LLCNevadaSalty Dog-I LLCMinnesotaSalty Dog-II LLCMinnesotaSand Ranch Windfarm, LLCOregonSendero Wind Energy, LLCDelawareShane’s Wind Machine LLCMinnesotaShooting Star Wind Project, LLCDelawareSimmons & Eastern, LLCDelawareSolarbridge Technologies Inc.DelawareStar Electricity, Inc.TexasSunnyside Cogeneration AssociatesUtahSunnyside Generation, LLCDelawareSunnyside II, Inc.DelawareSunnyside II, L.P.DelawareSunnyside III, Inc.DelawareSunnyside Properties, LLCUtahSunset Breeze, LLCMinnesotaThreemile Canyon Wind I, LLCOregonTitan STC, LLCDelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.TMI NQF, LLCNevadaTuana Springs Energy, LLCIdahoW&D Gas Partners, LLCDelawareWagon Trail, LLCOregonWally’s Wind Farm LLCMinnesotaWard Butte Windfarm, LLCOregonWater & Energy Savings Company, LLCDelawareWhitetail Wind Energy, LLCDelawareWildcat Finance, LLCDelawareWildcat Wind LLCNew MexicoWind Capital Holdings, LLCMissouriWindy Dog-1 LLCMinnesotaWolf Hollow I Power, LLCDelawareWolf Hollow II Power, LLCDelawareWolf Hollow Services, LLCDelawareWolf Wind Enterprises, LLCMinnesotaWolf Wind Transmission, LLCMinnesotaZion 1 NQF, LLCNevadaZion 2 NQF, LLCNevadaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 21.3 Commonwealth Edison Company Subsidiary JurisdictionComEd Financing III DelawareCommonwealth Edison Company of Indiana, Inc. IndianaRITELine Illinois, LLC IllinoisSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 21.4PECO Energy Company Subsidiary JurisdictionATNP Finance Company DelawareExTel Corporation, LLC DelawarePEC Financial Services, LLC PennsylvaniaPECO Energy Capital Corp. DelawarePECO Energy Capital, L.P. DelawarePECO Energy Capital Trust III DelawarePECO Energy Capital Trust IV DelawarePECO Energy Capital Trust V DelawarePECO Energy Capital Trust VI DelawarePECO Wireless, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 21.5Baltimore Gas and Electric Company Subsidiary JurisdictionBGE Capital Trust II DelawareRSB BondCo LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. No.333-196220) and on Form S-8 (No.333-189849,No.333-175162, No.333-127377, No.333-37082 and No.333-49780) of Exelon Corporation of our report dated February 13, 2015 relating to the financialstatements, financial statement schedules and the effectiveness of internal control over financial reporting of Exelon Corporation, which appears in this Form10-K./s/ PricewaterhouseCoopers LLPChicago, IllinoisFebruary 13, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.2CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-196220-04) and Form S-4 (No. 333-184712) ofExelon Generation Company, LLC of our report dated February 13, 2015 relating to the financial statements, financial statement schedule and theeffectiveness of internal control over financial reporting of Exelon Generation Company, LLC, which appears in this Form 10-K./s/ PricewaterhouseCoopers LLPBaltimore, MarylandFebruary 13, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.3CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-196220-03) of Commonwealth Edison Company ofour report dated February 13, 2015 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financialreporting of Commonwealth Edison Company, which appears in this Form 10-K./s/ PricewaterhouseCoopers LLPChicago, IllinoisFebruary 13, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.4CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-196220-02) of PECO Energy Company of our reportdated February 13, 2015 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting ofPECO Energy Company, which appears in this Form 10-K./s/ PricewaterhouseCoopers LLPPhiladelphia, PennsylvaniaFebruary 13, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 23.5CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-196220-01) of Baltimore Gas and Electric Companyof our report dated February 13, 2015 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financialreporting of Baltimore Gas and Electric Company, which appears in this Form 10-K./s/ PricewaterhouseCoopers LLPBaltimore, MarylandFebruary 13, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.1POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Anthony K. Anderson, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either ofthem, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Anthony K. AndersonAnthony K. AndersonDATE: February 9, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.2POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Ann C. BerzinAnn C. BerzinDATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.3POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, John A. Canning, Jr., do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ John A. Canning, Jr.John A. Canning, Jr.DATE: February 11, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.4POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Darryl M. Bradford attorney for me and in my name and on mybehalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Exelon Corporation, together with any amendments thereto,to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully andeffectually in all respects as I could do if personally present. /s/ Christopher M. CraneChristopher M. CraneDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.5POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Yves C. de Balmann, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Yves C. de BalmannYves C. de BalmannDATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.6POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either ofthem, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Nicholas DeBenedictisNicholas DeBenedictisDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.7POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Paul Joskow, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Paul L. JoskowPaul L. JoskowDATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.9POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Robert J. Lawless, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Robert J. LawlessRobert J. LawlessDATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.10POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Richard W. Mies, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Richard W. MiesRichard W. MiesDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.11POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, William C. Richardson, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either ofthem, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ William C. RichardsonWilliam C. RichardsonDATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.12POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, John W. Rogers, Jr., do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ John W. Rogers, Jr.John W. Rogers, Jr.DATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.13POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Mayo A. Shattuck III, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Mayo A. Shattuck IIIMayo A. Shattuck IIIDATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.14POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Stephen D. Steinour, do hereby appoint Christopher M. Crane and Darryl M. Bradford, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of ExelonCorporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Stephen D. SteinourStephen D. SteinourDATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.15POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, James W. Compton, do hereby appoint Anne R. Pramaggiore and Thomas S. O’Neill, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of CommonwealthEdison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ James W. ComptonJames W. ComptonDATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.16POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Anne R. Pramaggiore and Thomas S. O’Neill, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of CommonwealthEdison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Christopher M. CraneChristopher M. CraneDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.17POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, A. Steven Crown, do hereby appoint Anne R. Pramaggiore and Thomas S. O’Neill, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of CommonwealthEdison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ A. Steven CrownA. Steven CrownDATE: February 3, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.18POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Anne R. Pramaggiore and Thomas S. O’Neill, or either ofthem, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 ofCommonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do andperform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Nicholas DeBenedictisNicholas DeBenedictisDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.19POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Peter V. Fazio, Jr., do hereby appoint Anne R. Pramaggiore and Thomas S. O’Neill, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of CommonwealthEdison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Peter V. Fazio, Jr.Peter V. Fazio, Jr.DATE: February 5, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.20POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Michael H. Moskow, do hereby appoint Anne R. Pramaggiore and Thomas S. O’Neill, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of CommonwealthEdison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Michael H. MoskowMichael H. MoskowDATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.21POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien, do hereby appoint Anne R. Pramaggiore and Thomas S. O’Neill, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of CommonwealthEdison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Denis P. O’BrienDenis P. O’BrienDATE: February 3, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.22POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore, do hereby appoint Thomas S. O’Neill attorney for me and in my name and on mybehalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Commonwealth Edison Company, together with anyamendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in thepremises as fully and effectually in all respects as I could do if personally present. /s/ Anne R. PramaggioreAnne R. PramaggioreDATE: February 10, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.24POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Craig L. Adams, do hereby appoint Romulo L. Diaz, Jr. attorney for me and in my name and on mybehalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of PECO Energy Company, together with any amendmentsthereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fullyand effectually in all respects as I could do if personally present. /s/ Craig L. AdamsCraig L. AdamsDATE: February 3, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.25POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Craig L. Adams and Romulo L. Diaz, Jr., or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of PECO EnergyCompany, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Christopher M. CraneChristopher M. CraneDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.26POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, M. Walter D’Alessio, do hereby appoint Craig L. Adams and Romulo L. Diaz, Jr., or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of PECO EnergyCompany, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ M. Walter D’AlessioM. Walter D’AlessioDATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.27POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Craig L. Adams and Romulo L. Diaz, Jr., or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of PECO EnergyCompany, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Nicholas DeBenedictisNicholas DeBenedictisDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.30POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien, do hereby appoint Craig L. Adams and Romulo L. Diaz, Jr., or either of them, attorneyfor me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of PECO Energy Company,together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to bedone in the premises as fully and effectually in all respects as I could do if personally present. /s/ Denis P. O’BrienDenis P. O’BrienDATE: February 3, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.31POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Ronald Rubin, do hereby appoint Craig L. Adams and Romulo L. Diaz, Jr., or either of them, attorney forme and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of PECO Energy Company,together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to bedone in the premises as fully and effectually in all respects as I could do if personally present. /s/ Ronald RubinRonald RubinDATE: February 3, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.32POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin, do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them, attorneyfor me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas & ElectricCompany, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Ann C. BerzinAnn C. BerzinDATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.33POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas &Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Christopher M. CraneChristopher M. CraneDATE: February 8, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.34POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Michael E. Cryor, do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas &Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Michael E. CryorMichael E. CryorDATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.35POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, James R. Curtiss, do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them, for meand in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas & ElectricCompany, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all thingsnecessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ James R. CurtissJames R. CurtissDATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.36POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, Jr., do hereby appoint Daniel P. Gahagan attorney for me and in my name and on mybehalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas & Electric Company, together with anyamendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in thepremises as fully and effectually in all respects as I could do if personally present. /s/ Calvin G. Butler, Jr.Calvin G. Butler, Jr.DATE: February 6, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.37POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Joseph Haskins, Jr., do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas &Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Joseph Haskins, Jr.Joseph Haskins, Jr.DATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.38POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Carla D. Hayden, do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas &Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Carla D. HaydenCarla D. HaydenDATE: February 3, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.39POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien, do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas &Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Denis P. O’BrienDenis P. O’BrienDATE: February 3, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 24.40POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Michael D. Sullivan, do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, or either of them,attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2014 of Baltimore Gas &Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform allthings necessary to be done in the premises as fully and effectually in all respects as I could do if personally present. /s/ Michael D. SullivanMichael D. SullivanDATE: February 4, 2015Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-1 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Christopher M. Crane, certify that: 1.I have reviewed this annual report on Form 10-K of Exelon Corporation; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ CHRISTOPHER M. CRANE President and Chief Executive Officer(Principal Executive Officer) 514Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-2 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Jonathan W. Thayer, certify that: 1.I have reviewed this annual report on Form 10-K of Exelon Corporation; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ JONATHAN W. THAYER Senior Executive Vice President and Chief Financial Officer(Principal Financial Officer) 515Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-3 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Kenneth W. Cornew, certify that: 1.I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ KENNETH W. CORNEW President and Chief Executive Officer(Principal Executive Officer) 516Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-4 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Bryan P. Wright, certify that: 1.I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ BRYAN P. WRIGHT Chief Financial Officer(Principal Financial Officer) 517Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-5 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Anne R. Pramaggiore, certify that: 1.I have reviewed this annual report on Form 10-K of Commonwealth Edison Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ ANNE R. PRAMAGGIORE President and Chief Executive Officer(Principal Executive Officer) 518Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-6 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Joseph R. Trpik, Jr., certify that: 1.I have reviewed this annual report on Form 10-K of Commonwealth Edison Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ JOSEPH R. TRPIK, JR. Senior Vice President, Chief Financial Officer and Treasurer(Principal Financial Officer) 519Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-7 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Craig L. Adams, certify that: 1.I have reviewed this annual report on Form 10-K of PECO Energy Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ CRAIG L. ADAMS President and Chief Executive Officer(Principal Executive Officer) 520Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-8 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Phillip S. Barnett, certify that: 1.I have reviewed this annual report on Form 10-K of PECO Energy Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ PHILLIP S. BARNETT Senior Vice President, Chief Financial Officer and Treasurer(Principal Financial Officer) 521Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-9 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, Calvin G. Butler, Jr., certify that: 1.I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ CALVIN G. BUTLER Chief Executive Officer(Principal Executive Officer) 522Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 31-10 CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THESECURITIES AND EXCHANGE ACT OF 1934 I, David M. Vahos, certify that: 1.I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and15d-15(f)) for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonablylikely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: February 13, 2015 /s/ DAVID M. VAHOS Vice President, Chief Financial Officer and Treasurer(Principal Financial Officer) 523Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-1 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2014, that(i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the informationcontained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation. Date: February 13, 2015 /s/ CHRISTOPHER M. CRANE Christopher M. CranePresident and Chief Executive Officer 524Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-2 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2014, that(i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the informationcontained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation. Date: February 13, 2015 /s/ JONATHAN W. THAYER Jonathan W. ThayerSenior Executive Vice President and Chief FinancialOfficer 525Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-3 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year endedDecember 31, 2014, that (i) the report fully complies with the requirements of section 13(a) or 15 (d) of the Securities Exchange Act of 1934, and(ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of ExelonGeneration Company, LLC. Date: February 13, 2015 /s/ KENNETH W. CORNEW Kenneth W. CornewPresident and Chief Executive Officer 526Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-4 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year endedDecember 31, 2014, that (i) the report fully complies with the requirements of section 13(a) or 15 (d) of the Securities Exchange Act of 1934, and(ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of ExelonGeneration Company, LLC. Date: February 13, 2015 /s/ BRYAN P. WRIGHT Bryan P. WrightChief Financial Officer 527Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-5 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year endedDecember 31, 2014, that (i) the report fully complies with the requirements of section 13(a) or 15 (d) of the Securities Exchange Act of 1934, and(ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations ofCommonwealth Edison Company. Date: February 13, 2015 /s/ ANNE R. PRAMAGGIORE Anne R. PramaggiorePresident and Chief Executive Officer 528Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-6 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year endedDecember 31, 2014, that (i) the report fully complies with the requirements of section 13(a) or 15 (d) of the Securities Exchange Act of 1934, and(ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations ofCommonwealth Edison Company. Date: February 13, 2015 /s/ JOSEPH R. TRPIK, JR. Joseph R. Trpik, Jr.Senior Vice President, Chief Financial Officer andTreasurer 529Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-7 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2014,that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the informationcontained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company. Date: February 13, 2015 /s/ CRAIG L. ADAMS Craig L. AdamsPresident and Chief Executive Officer 530Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-8 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2014,that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the informationcontained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company. Date: February 13, 2015 /s/ PHILLIP S. BARNETT Phillip S. BarnettSenior Vice President, Chief Financial Officer andTreasurer 531Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-9 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Baltimore Gas and Electric Company for the year endedDecember 31, 2014, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and(ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gasand Electric Company. Date: February 13, 2015 /s/ CALVIN G. BUTLER, JR. Calvin G. Butler, Jr.Chief Executive Officer 532Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Exhibit 32-10 Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code The undersigned officer hereby certifies, as to the Report on Form 10-K of Baltimore Gas and Electric Company for the year endedDecember 31, 2014, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and(ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gasand Electric Company. Date: February 13, 2015 /S/ DAVID M. VAHOS David M. VahosVice President, Chief Financial Officer and Treasurer 533Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 13, 2015Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.

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