Exelon
Annual Report 2015

Plain-text annual report

Morningstar® Document Research℠ FORM 10-KBALTIMORE GAS & ELECTRIC CO - EXCFiled: February 10, 2016 (period: December 31, 2015)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 ContentsUNITED 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, 2015 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(800) 483-3220 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Smaller 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, 2015was as follows: Exelon Corporation Common Stock, without par value $ 27,049,825,290Exelon 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, 2016 was as follows: Exelon Corporation Common Stock, without par value 919,924,742Exelon Generation Company, LLC not applicableCommonwealth Edison Company Common Stock, $12.50 par value 127,016,973PECO 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 2016 Annual Meeting ofShareholders and the Commonwealth Edison Company 2016 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 GeneralSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 19 Baltimore Gas and Electric Company 19 Employees 23 Environmental Regulation 24 Executive Officers of the Registrants 30 ITEM 1A. RISK FACTORS 34 ITEM 1B. UNRESOLVED STAFF COMMENTS 61 ITEM 2. PROPERTIES 62 Exelon Generation Company, LLC 62 Commonwealth Edison Company 65 PECO Energy Company 65 Baltimore Gas and Electric Company 66 ITEM 3. LEGAL PROCEEDINGS 67 Exelon Corporation 67 Exelon Generation Company, LLC 67 Commonwealth Edison Company 67 PECO Energy Company 67 Baltimore Gas and Electric Company 67 ITEM 4. MINE SAFETY DISCLOSURES 67 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIES 68 ITEM 6. SELECTED FINANCIAL DATA 72 Exelon Corporation 72 Exelon Generation Company, LLC 73 Commonwealth Edison Company 74 PECO Energy Company 74 Baltimore Gas and Electric Company 75 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS 76 Exelon Corporation 76 Executive Overview 76 Critical Accounting Policies and Estimates 100 Results of Operations 117 Liquidity and Capital Resources 148 Exelon Generation Company, LLC 182 Commonwealth Edison Company 184 PECO Energy Company 186 Baltimore Gas and Electric Company 188 Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 169 Exelon Corporation 169 Exelon Generation Company, LLC 170 Commonwealth Edison Company 171 PECO Energy Company 171 Baltimore Gas and Electric Company 172 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 190 Exelon Corporation 201 Exelon Generation Company, LLC 207 Commonwealth Edison Company 213 PECO Energy Company 219 Baltimore Gas and Electric Company 225 Combined Notes to Consolidated Financial Statements 230 1. Significant Accounting Policies 230 2. Variable Interest Entities 247 3. Regulatory Matters 256 4. Mergers, Acquisitions, and Dispositions 283 5. Investment in Constellation Energy Nuclear Group, LLC 289 6. Accounts Receivable 293 7. Property, Plant and Equipment 294 8. Impairment of Long-Lived Assets 297 9. Implications of Potential Early Plant Retirements 300 10. Jointly Owned Electric Utility Plant 301 11. Intangible Assets 302 12. Fair Value of Financial Assets and Liabilities 307 13. Derivative Financial Instruments 322 14. Debt and Credit Agreements 338 15. Income Taxes 348 16. Asset Retirement Obligations 356 17. Retirement Benefits 365 18. Contingently Redeemable Noncontrolling Interest 381 19. Shareholder’s Equity 382 20. Stock-Based Compensation Plans 383 21. Earnings Per Share 389 22. Changes in Accumulated Other Comprehensive Income 390 23. Commitments and Contingencies 394 24. Supplemental Financial Information 411 25. Segment Information 419 26. Related Party Transactions 424 27. Quarterly Data 432 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURE 435 ITEM 9A. CONTROLS AND PROCEDURES 435 Exelon Corporation 435 Exelon Generation Company, LLC 435 Commonwealth Edison Company 435 PECO Energy Company 435 Baltimore Gas and Electric Company 435 ITEM 9B. OTHER INFORMATION 436 Exelon Corporation 436 Exelon Generation Company, LLC 436 Commonwealth Edison Company 436 PECO Energy Company 436 Baltimore Gas and Electric Company 436 Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 437 ITEM 11. EXECUTIVE COMPENSATION 438 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERS 439 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 440 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 441 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 442 SIGNATURES 476 Exelon Corporation 476 Exelon Generation Company, LLC 477 Commonwealth Edison Company 478 PECO Energy Company 479 Baltimore Gas and Electric Company 480 Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 InfrastructureAMP Advanced Metering ProgramARC 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 RuleCAP Customer Assistance Program 1Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 AbbreviationsCERCLA Comprehensive Environmental Response, Compensation and Liability Act of 1980, asamendedCFL 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 ChargeD.C. 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 SA and its subsidiariesEE&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 Code 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 AbbreviationsIRS Internal Revenue ServiceISO 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 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 Calvert Cliffs, Nine MilePoint, Ginna, Clinton, Oyster Creek, Three Mile Island, Zion (a former ComEd unit), andportions of Peach Bottom (a former PECO unit)NOSA Nuclear Operating Services AgreementNOV 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 ClausePHI Pepco Holdings, Inc. 3Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 AbbreviationsPJM PJM Interconnection, LLCPOLR Provider of Last ResortPOR 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 CommitteeROE Return on Common EquityRPM 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 23; 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 and power marketing business, and through ComEd, PECO and BGE, in the energy delivery businesses discussed below. Exelon’sprincipal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 800-483-3220. 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 PowerRegions. 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 25—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 first quarter of 2016. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes toConsolidated 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, including renewable energy, to both wholesale and retail customers. The retail sales include commercial, industrial andresidential customers. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customersunder long-term and short-term contracts, and in wholesale power markets. Generation operates in well-developed energy markets and employs anintegrated hedging strategy to manage commodity price volatility. Generation’s fleet, including its nuclear plants which consistently operate at highcapacity factors, also provides geographic and supply source diversity. These factors help Generation mitigate the challenging conditionsemanating from competitive energy markets. Generation’s customers include distribution utilities, municipalities, cooperatives, financialinstitutions, and commercial, industrial, governmental, and residential customers in competitive markets. Generation’s customer facing activitiesfoster development and delivery of other innovative energy-related products and services for its customers. Generation also engages in natural gasand oil exploration and production activities (Upstream). Generation is a public utility under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales 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 not limited to,third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existingoperational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate 7Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsreorganizations; and certain holding company acquisitions of public utility and holding company securities. Additionally, ERCOT is not subject toregulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. Specific operations ofGeneration are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC and Federal and stateenvironmental protection agencies. Additionally, Generation is subject to mandatory reliability standards promulgated by the NERC, with theapproval 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. 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 4,007 MW. See ITEM 2. PROPERTIES for additional informationon these sites. Generation and EDF also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has the option, exercisable beginningon January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determinedby agreement of the parties, or absent agreement, a third-party arbitration process. In addition, under limited circumstances, the period for exerciseof the put option may be extended for 18 months. 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 a fully consolidated basis in Exelon’sand Generation’s Consolidated Balance Sheets. Refer to Note 5— Investment in Constellation Energy Nuclear Group, LLC of the Combined Notesto Consolidated Financial Statements for further information regarding the integration transaction. Significant Acquisitions Integrys Energy Services, Inc. On November 1, 2014, Generation acquired the competitive retail electric and natural gas 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 were excludedfrom the transaction. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements foradditional information on the above acquisition. Merger with Constellation Energy Group, Inc. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as thesurviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger. Since the merger transaction, Generationincludes the former Constellation generation and customer supply operations. 8Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 completed the acquisition of all of the interests in Antelope Valley, a242-MW solar project under development in northern Los Angeles County, California, from First Solar, Inc. The facility became fully operational in2014. The project has a 25-year PPA with Pacific Gas & Electric Company for the full output of the plant, which has been approved by the CPUC.Total capitalized costs for the facility incurred through completion of the project 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, 2015, Generation has sold certain generating assets with total pre-tax proceeds of $1.8 billion(after-tax proceeds of approximately $1.4 billion). The proceeds are expected to be used primarily to finance a portion of the acquisition of PHI. Maryland Clean Coal Stations. On November 30, 2012, a subsidiary of Generation sold the Brandon Shores generating station and H.A.Wagner generating station in Anne Arundel County, Maryland, and the C.P. Crane generating station in Baltimore County, Maryland to 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, 2015, the generating resources of Generation consisted of the following: Type of Capacity MW Owned generation assets Nuclear 19,460 Fossil (primarily natural gas) 9,682 Renewable 3,599 Owned generation assets 32,741 Long-term power purchase contracts 7,419 Total generating resources 40,160 (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)Includes hydroelectric, wind, and solar generating assets. Generation has six reportable segments, the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions,representing the different geographical areas in which Generation’s customer-facing activities are conducted and where Generation’s generatingresources are located. • 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 36% of capacity). 9 (a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 37% 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 Power Regions is an aggregate of regions not considered individually significant (approximately 6% of capacity). See Note 25—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 of19,460 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 Cliffs, Nine Mile Point [excluding LIPA’s 18% ownership interest in Nine Mile PointUnit 2] and R.E. Ginna) which are 100% consolidated on Exelon and Generation’s financial statements as of April 1, 2014. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for additional information. Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated byPSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2015, 2014 and 2013 electric supply (in GWh) generatedfrom the nuclear generating facilities was 68%, 67% and 57%, 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015, 2014 and 2013, the nuclear generating facilities operated by Generation achieved capacity factors of 93.7%, 94.3% and 94.1%,respectively. The capacity factors reflect ownership percentage of stations operated by Generation and include CENG as of April 1, 2014.Generation manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resultingin a stable generation base for Generation’s wholesale and retail marketing and trading activities. During scheduled refueling outages, Generationperforms maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. In addition to the maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation hasextensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation has extensive safety systems inplace to protect the plant, personnel and surrounding area in the unlikely event of an accident or other incident. 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 January 6, 2016, the NRC categorized Clinton and Dresden unit 2 in the RegulatoryResponse Column, which is the second highest of five performance bands. All other units operated by Generation are categorized in the LicenseeResponse Column as of December 31, 2015, which is the highest performance band. The NRC may modify, suspend or revoke operating licensesand impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the operating licenses.Changes in regulations by the NRC may require a substantial increase in capital expenditures for nuclear generating facilities and/or increasedoperating 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, Limerick Units 1 and 2, Byron Units 1 and 2 and Braidwood Units 1 and2. Additionally, PSEG has 40-year operating licenses from the NRC and has received 20-year operating license renewals for Salem Units 1 and 2.On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019.The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service: Station Unit In-ServiceDate Current LicenseExpiration Braidwood 1 1988 2046 2 1988 2047 Byron 1 1985 2044 2 1987 2046 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 December 2014, Generation submitted applications to the NRC to extend the operating licenses of LaSalle Units 1 and 2 by 20 years.(c)Stations for which the NRC has issued renewed operating licenses.(d)Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has advised the NRC that any license renewal application would not be fileduntil the first quarter of 2021.(e)In December 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. Generation currently has a license renewal application pending for LaSalle Units 1 and 2. Generation has advised the NRC that any licenserenewal application for Clinton would not be filed until the first quarter of 2021. The operating license renewal process takes approximately four tofive years from the commencement of the renewal process until completion of the NRC’s review. The NRC review process takes approximatelytwo years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the original operatinglicense expiration. Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual and assumed renewal ofoperating licenses for all of Generation’s operating nuclear generating stations except for Oyster Creek. 12 (a) (c) (c) (c) (d) (c) (b) (c) (c) (c)(e) (c) (c) (c) (c) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Once all projects are completed in 2016, Generation will have placed in-service538 MWs of new nuclear generation. As of December 31, 2015, under the nuclear uprate program, Generation has placed into service projects representing 536 MWs of newnuclear generation at a cost of $1,436 million, which has been capitalized to property, plant and equipment on Exelon’s and Generation’sConsolidated Balance Sheets. Nuclear Waste Storage and Disposal. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in theUnited States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities inon-site storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity forthe life of the respective plant, Generation has developed dry cask storage facilities to support operations. As of December 31, 2015, Generation had approximately 75,800 SNF assemblies (18,800 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 16—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, in which on-site dry cask storage will be in operation at Clinton in 2016 and is projectedto be in operation at Three Mile Island in 2023. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all currentand 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 23—Commitments andContingencies of the Combined Notes to Consolidated Financial Statements. As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station 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 all its stations to stage for shipping campaigns and store, as needed, Class B and Class CLLRW. Generation has a contract through 2032 to ship Class B 13Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently storedat each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRWfrom Generation’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still berequired to utilize on-site storage at its stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store allClass B and C LLRW for the life of all stations in Generation’s nuclear fleet. Generation continues to pursue alternative disposal strategies forLLRW, 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 23—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 12—Fair Value of Financial Assets and Liabilities and Note 16—Asset Retirement Obligations of the CombinedNotes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations. 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 16—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. 14Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFossil and Renewable Facilities (including Hydroelectric) Generation has ownership interests in 13,281 MW of capacity in fossil and renewable generating facilities currently in service. Generationwholly owns all of its fossil and renewable generating stations, with the exception of: (1) jointly owned facilities that include Wyman; (2) anownership interest through an equity method investment in Sunnyside; (3) certain wind project entities with minority interest owners; and (4) anownership interest in the Albany Green Energy, LLC project entity, see Note 2— Variable Interest Entities of the Combined Notes to ConsolidatedFinancial Statements for additional information on these wind project entities. Generation’s fossil and renewable generating stations are alloperated by Generation, with the exception of LaPorte, Sunnyside and Wyman, which are operated by third parties. In 2015, 2014 and 2013,electric supply (in GWh) generated from owned fossil and renewable generating facilities was 8%, 13% and 15%, respectively, of Generation’stotal electric supply. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. Foradditional information regarding Generation’s electric generating facilities, see ITEM 2. PROPERTIES—Exelon Generation Company, LLC andITEM 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. On December 22, 2015, FERC issued a new 40-year license for Muddy Run. Thelicense term expires on December 1, 2055. Based on the FERC procedural schedule, the FERC licensing process was not completed prior to theexpiration of Conowingo’s license on September 1, 2014. FERC is required to issue an annual license for a facility until the new license is issued.On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. If FERC does notissue a new license prior to the expiration of annual license, the annual license will renew automatically. The stations are currently beingdepreciated over their estimated useful lives, which includes the license renewal period. Refer to Note 3—Regulatory Matters of the CombinedNotes to Consolidated Financial Statements for additional information. Insurance. Generation maintains business interruption insurance for its renewable and fossil projects, and delay in start-up insurance for itsrenewable and fossil projects currently under construction. Generation does not purchase business interruption insurance for its wholly ownedfossil and hydroelectric operations, unless required by financing agreements; see Note 14—Debt and Credit Agreements of the Combined Notes toConsolidated Financial Statements for additional information on financing agreements. Generation maintains both property damage and liabilityinsurance. For property damage and liability claims for these operations, Generation is self-insured to the extent that losses are within the policydeductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’sfinancial condition and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES—Exelon Generation Company, LLC. 15Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsLong-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, 2015: Region Number ofAgreements Expiration Dates Capacity (MW) Mid-Atlantic 16 2016 - 2032 805 Midwest 7 2016 - 2022 1,536 New England 8 2016 - 2017 650 ERCOT 5 2020 - 2031 1,501 Other Power Regions 12 2016 - 2030 2,927 Total 48 7,419 2016 2017 2018 2019 2020 Capacity Expiring (MW) 586 1,761 101 627 980 Fuel The following table shows sources of electric supply in GWh for 2015 and 2014: Source of Electric Supply 2015 2014 Nuclear 175,474 166,454 Purchases—non-trading portfolio 61,592 48,200 Fossil (primarily natural gas) 14,937 26,324 Renewable 5,982 6,429 Total supply 257,985 247,407 (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 2015 and 2014 includes physical volumes of 33,415 GWh and 25,053 GWh, respectively, for CENG.(b)Purchased power for 2015 and 2014 includes physical volumes of 0 GWh and 5,346 GWh, respectively, as a result of the PPA with CENG. On April 1, 2014, Generation assumedoperational control of CENG’s nuclear fleet. As a result, 100% of CENG volumes are included in nuclear generation after April 1, 2014.(c)Includes hydroelectric, wind, and solar generating assets. The fuel costs per MWh for nuclear generation are less than those for fossil-fuel generation. Consequently, nuclear generation is 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 2018.Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2018. All of Generation’senrichment requirements have been contracted through 2020. Contracts for fuel fabrication have been obtained through 2022. 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. 16(a) (b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 13—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 in the market tomeet the energy demand of its customers. Generation sells electricity, natural gas, and related products and solutions to various customers,including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitivemarkets. Generation’s customer facing operations combine a unified sales force with a customer-centric model that leverages technology tobroaden the range of products and solutions offered, which Generation believes promotes stronger customer relationships. This model focuses onefficiency and cost reduction, which provides a platform that is scalable and able to capitalize on opportunities for future growth. Generation may purchase more than the energy demanded by its customers. Generation then sells this open position, along with capacitynot used to meet customer demand, in the wholesale electricity markets. Where necessary, Generation also purchases transmission service toensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs in markets without anorganized RTO. Generation also incorporates contingencies into its planning for extreme weather conditions, including potentially reservingcapacity to meet summer loads at levels representative of warmer-than-normal weather conditions. Additionally, Generation is involved in thedevelopment, 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 2016 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. As of December 31, 2015, the percentage of expected generation hedged for the major reportable segments was 90%-93%,60%-63% and 28%-31% for 2016, 2017, and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent salesdivided by the expected generation. 17Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacitybased upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes forpower, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including sales to ComEd, PECO and BGE to serve their retail load. A portion of Generation’s hedging strategy may beimplemented through the use of fuel products based on assumed correlations between power and fuel prices, which routinely change in the market.The corporate risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retail power marketing activities.Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion ofGeneration’s efforts. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits,including volume, stop-loss and value-at-risk limits, to manage exposure to market risk. See ITEM 7A. QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK for additional information. At December 31, 2015, 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 2016 $262 $229 $15 $506 2017 197 269 21 487 2018 92 115 23 230 2019 97 34 24 155 2020 40 1 16 57 Thereafter 221 1 35 257 Total $909 $649 $134 $1,692 (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, 2015, 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, 2015, capacity offsets were $146 million, $149 million,$150 million, $151 million, $142 million, and $462 million for years 2016, 2017, 2018, 2019, 2020, 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. 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 2016 are as follows: (in millions) Nuclear fuel $1,150 Growth 1,350 Production plant 950 Renewable energy projects 25 Other 125 Total $3,600 (a)Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant.(b)Includes the CENG units on a fully consolidated basis. 18(a)(b)(c) (a)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 ComEd is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution andtransmission services to retail customers in northern Illinois. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation bythe ICC related to distribution rates and service, the issuance of securities and certain other aspects of ComEd’s business. ComEd is a publicutility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of ComEd’s business.Specific operations of ComEd are also subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, ComEdis subject to NERC mandatory reliability standards. 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 2016 to 2066. ComEd anticipates working with the appropriate governmental bodiesto extend or replace the franchise agreements prior to expiration. PECO PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution andtransmission 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 related to electric and gasdistribution rates and service, the issuances of certain securities and certain other aspects of PECO’s business. PECO is a public utility under theFederal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of PECO’s business and by the U.S.Department of Transportation related to pipeline safety and other areas of gas operations. Specific operations of PECO are subject to thejurisdiction of various other Federal, state, regional and local agencies. Additionally, PECO is also subject to NERC mandatory reliabilitystandards. PECO has the necessary authorizations to provide regulated electric and natural gas distribution services 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. BGE BGE is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmissionservices 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 related to electric and gas distribution rates andservice, the issuances of certain securities and certain other aspects of BGE’s business. BGE is a public utility under the Federal Power Actsubject to regulation by FERC related to transmission rates and certain other aspects of BGE’s business and by the U.S. Department ofTransportation related to pipeline safety and other areas of gas operations. Specific operations of BGE are subject to the jurisdiction of variousother Federal, state, regional and local agencies. Additionally, BGE is also subject to NERC mandatory reliability standards. 19Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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. ComEd, PECO and BGE Utility Operations Service Territories. The following table presents the size of retail service territories, populations of each retail service territory and thenumber of retail customers within each retail service territory for ComEd, PECO and BGE as of December 31, 2015: Retail Service Territories(in square miles) Retail Service Territory Population(in millions) Number of Retail Customers(in millions) Total Electric Natural gas Total Electric Natural gas Total Electric Natural gas ComEd 11,400 11,400 n/a 9.0 9.0 n/a 3.8 3.8 n/a PECO 2,100 1,900 1,900 4.6 4.0 3.1 2.1 1.6 0.5 BGE 2,300 2,300 800 3.0 3.0 1.7 1.3 1.3 0.7 (a)Includes approximately 2.8 million in the city of Chicago.(b)Includes approximately 1.6 million in the city of Philadelphia.(c)Includes approximately 0.6 million in the city of Baltimore. Peak Deliveries. ComEd, PECO and BGE electric sales and peak load are generally higher during the summer and winter months, whentemperature extremes create demand for either summer cooling or winter heating. For PECO and BGE, natural gas sales are generally higherduring the winter months when cold temperatures create demand for winter heating. The following table summarizes peak deliveries for ComEd, PECO and BGE for electric and gas deliveries during peak demand months asof December 31, 2015: Electric Peak Deliveries(in GW) Natural Gas Peak Deliveries(in mmcfs) Summerpeak date Summerdeliveries Winter peakdate Winterdeliveries Winter peak date Winter deliveries ComEd 7/20/2011 23.75 1/6/2014 16.51 n/a n/a PECO 7/22/2011 8.98 1/7/2014 7.17 2/15/2015 777 BGE 7/21/2011 7.23 2/20/2015 6.71 2/19/2015 777 Electric and Natural Gas Distribution Services. ComEd, PECO and BGE are allowed to recover reasonable costs and fair and prudent capitalexpenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commissionapproval. ComEd recovers costs through a performance-based rate formula, pursuant to EIMA. ComEd is required to file an update to theperformance-based rate formula on an annual basis. PECO’s and BGE’s electric and gas distribution costs are recovered through traditional ratecase proceedings. In certain instances, ComEd, PECO and BGE use specific recovery mechanisms as approved by the ICC, PAPUC, andMDPSC, respectively. 20(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThrough the ICC, ComEd is obligated to deliver electricity to customers in their respective service territories and also retain significantdefault service obligations (referred to as POLR) to provide electricity to certain groups of customers in their respective service areas who do notchoose a competitive electric generation supplier. Through the PAPUC and MDPSC, PECO and BGE, respectively, are obligated to deliverelectricity and natural gas to customers in their respective service territories and also retain significant default service obligations (referred to asDSP and SOS for electric and PGC and MBR for natural gas, respectively) to provide electricity or natural gas to certain groups of customers intheir respective service areas who do not choose a competitive electric generation supplier or a competitive natural gas supplier. ComEd ispermitted to recover electric costs, and PECO and BGE are permitted to recover electric and natural gas procurement costs from retail customers.Therefore, fluctuations in electric and natural gas procurement costs have no impact on electric and natural gas revenue net of purchased powerand fuel expense. ComEd customers have the choice to purchase electricity, and PECO and BGE customers have the choice to purchase electricity andnatural gas from competitive electric generation and natural gas suppliers. The customer’s choice of suppliers does not impact the volume ofdeliveries, but affects revenues collected from customers related to supplied energy and natural gas service. Customer choice program activityhas no impact on electric and gas revenue net of purchased power and fuel expense. For those customers that choose a competitive electricgeneration or natural gas supplier, ComEd, PECO and BGE may act as the billing agent but do not record revenues or purchased power and fuelexpense related to the electric and natural gas procurement costs. ComEd, PECO and BGE remain the distribution service providers for allcustomers in their respective service territories and charge a regulated rate for distribution service. Retail customers participating in customer choice programs, and retail deliveries purchased from competitive electric generation and naturalgas suppliers (as a percentage of GWh and mmcf sales, respectively) for ComEd, PECO and BGE consisted of the following at December 31,2015, 2014 and 2013: December 31, 2015 Number of retail customers % of total retail customers Deliveries as a % of retail sales(for the year ended) Electric Natural gas Electric Natural gas Electric Natural gas ComEd 1,655,400 n/a 42% n/a 76% n/a PECO 563,400 81,100 35% 16% 70% 25% BGE 343,000 154,000 27% 23% 61% 56% December 31, 2014 Number of retail customers % of total retail customers Deliveries as a % of retail sales(for the year ended) Electric Natural gas Electric Natural gas Electric Natural gas ComEd 2,426,900 n/a 63% n/a 80% n/a PECO 546,900 78,400 34% 16% 70% 22% BGE 364,000 161,000 29% 25% 60% 53% December 31, 2013 Number of retail customers % of total retail customers Deliveries as a % of retail sales(for the year ended) Electric Natural gas Electric Natural gas Electric Natural gas ComEd 2,630,200 n/a 68% n/a 81% n/a PECO 531,500 66,400 34% 13% 68% 19% BGE 399,000 172,000 32% 26% 61% 54% (a)In September 2015, the City of Chicago discontinued its participation in the customer choice program and began purchasing its electricity from ComEd. Approximately 670,000customers were impacted by the City of Chicago’s decision which resulted in the reduction in the number of customers participating in customer choice programs in 2015. 21(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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’s, PECO’s and BGE’s electric supply for its customers is primarily procured through contracts asrequired by the ICC, PAPUC and MDPSC, respectively. ComEd, PECO and BGE procure electricity supply from various approved bidders,including Generation. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power fromaffiliates on ComEd’s, PECO’s and BGE’s Statement of Operations and Comprehensive Income. PECO’s and BGE’s natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO and BGE haveannual firm supply from transportation contracts of 132,000 mmcf and 128,000 mmcf, respectively. In addition, to supplement gas supply at timesof heavy winter demands and in the event of temporary emergencies, PECO and BGE have available storage capacity from the following sources: Peak Natural Gas Sources (in mmcf) Liquefied NaturalGas Facility Propane-Air Plant Underground StorageService Agreements PECO 1,200 150 18,000 BGE 1,055 546 22,000 (a)Natural gas from underground storage represents approximately 28% and 31% of PECO and BGE’s 2015-2016 heating season planned supplies, respectively. PECO and BGE have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity orbundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of naturalgas. Earnings from these activities are shared between the utilities and customers. PECO and BGE make these sales as part of a program tobalance its supply and cost of natural gas. Energy Efficiency Programs. ComEd, PECO and BGE are also allowed to recover costs associated with energy efficiency and demandresponse programs. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demandresponse measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency. Capital Investment. ComEd’s, PECO’s and BGE’s businesses are capital intensive and requires significant investments, primarily in electrictransmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability and efficiency ofits system. ComEd’s, PECO’s and BGE’s most recent estimates of capital expenditures for plant additions and improvements for 2016 are $2,425million, $675 million and $825 million, respectively. ComEd, PECO and BGE each have ICC, PAPUC and MDPSC, respectively, approved smart meter and smart grid deployment programs toenhance their distribution systems. The following table summarizes ComEd’s smart meter and PECO’s and BGE’s smart meter and smart gridtechnology spending and meter installations as of December 31, 2015: December 31, 2015 Total Spend fromInception to Date Total Meters to be Installed Meters Installed to Date (in millions) Projected Actual Electric Natural gas Electric Natural gas ComEd $2,615 $1,526 4.0 n/a 2.0 n/a PECO 818 803 1.7 0.5 1.7 0.5 BGE 527 512 1.3 0.7 1.2 0.6 22 (a)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)ComEd has committed to invest approximately $2.6 billion over a ten year period to modernize and storm-harden its distribution system and to implement smart grid technology.These amounts represent capital expenditures associated with ComEd’s commitment.(b)PECO will seek recovery of costs associated with PECO’s gas AMI through the traditional rate case process.(c)BGE is seeking recovery of its smart grid initiative costs as part of its 2015 electric and gas distribution rate case. See Note 3—Regulatory Matters of the Combined Notes toConsolidated Financial Statements for additional information. Transmission Services. ComEd, PECO and BGE provide unbundled transmission service under rates approved by FERC. FERC has usedits regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitateregional wholesale markets. Under FERC’s open access transmission policy promulgated in Order No. 888, ComEd, PECO and BGE, as ownersof transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. ComEd, PECOand BGE are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public information between thetransmission owner’s employees and wholesale merchant employees. PJM is the ISO and the FERC-approved RTO for the Mid-Atlantic and Midwest regions. PJM is the transmission provider under, and theadministrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM 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 and BGE’s transmission rates are established based on a formula that was approved by FERC in January 2008 and April 2006,respectively. FERC’s order establishes the agreed-upon treatment of costs and revenues in the determination of network service transmissionrates and the process for updating the formula rate calculation on an annual basis. PECO’s customers are charged for PECO’s PJM retail transmission services on a full and current basis through a Transmission ServiceCharge (applicable to default service only) and through a Non-Bypassable Transmission Charge (applicable to all distribution customers) inaccordance with PECO’s approved distribution rates. See Note 3—Regulatory Matters, Note 25—Segment Information of the Combined Notes to Consolidated Financial Statements and ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and CapitalResources for further information. Employees As of December 31, 2015, Exelon and its subsidiaries had 29,762 employees in the following companies, of which 9,649 or 32% werecovered by collective bargaining agreements (CBAs): IBEW Local 15 IBEW Local 614 Other CBAs Total EmployeesCovered by CBAs TotalEmployees Generation 1,688 102 2,424 4,214 14,512 ComEd 3,996 — — 3,996 6,765 PECO — 1,327 — 1,327 2,641 BGE — — — — 3,293 Other 69 — 43 112 2,551 Total 5,753 1,429 2,467 9,649 29,762 23(a)(b)(c) (d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)A separate CBA between ComEd and IBEW Local 15 covers approximately 61 employees in ComEd’s System Services Group and was extended to April 1, 2016. Generation’sand ComEd’s separate CBAs with IBEW Local 15 expires in 2019.(b)1,327 PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614, both expiring in 2021. Additionally, Exelon Power, anoperating unit of Generation, has an agreement with IBEW Local 614, which expires in 2016 and covers 102 employees.(c)During 2015, Generation finalized its CBA with Clinton Local 51 which will expire in 2020; its two CBAs with Local 369 at Mystic 7 and Mystic 8/9, both expiring in 2020; and fourSecurity Officer unions at Braidwood, Byron, Clinton and TMI, all expiring between 2018 and 2021, respectively. During 2014, Generation finalized CBAs with TMI Local 777 andOyster Creek Local 1289, expiring in 2019 and 2021, respectively and CENG finalized its CBA with Nine Mile Point which will expire in 2020. Additionally, during 2014, Generationfinalized CBAs with the Security Officer unions at Dresden, LaSalle, Limerick and Quad Cities, which expire between 2017 and 2018. Lastly, during 2014, an agreement wasnegotiated with Las Vegas District Energy and IUOE Local 501, which will expire in 2018. During 2013, Generation finalized its CBA with the Security Officer union at OysterCreek, expiring in 2016; as well as two other 3-year agreements: New England ENEH, UWUA Local 369, which will expire in 2017; and New Energy IUOE Local 95-95A, which willexpire in 2016.(d)Other includes shared services employees at BSC. Environmental Regulation General Exelon, Generation, ComEd, PECO and BGE are subject to comprehensive and complex legislation regarding environmental matters by thefederal government and various state and local jurisdictions in which they operate their facilities. The Registrants are also subject to regulationsadministered by the EPA and various state and local environmental protection agencies. Federal, state and local regulation includes the authorityto 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 of Directors has delegated to itscorporate governance committee the authority to oversee Exelon’s compliance with laws and regulations and its strategies and efforts to protectand improve the quality of the environment, including Exelon’s climate change and sustainability policies and programs, as discussed in furtherdetail below. The Exelon Board of Directors has also delegated to its Generation Oversight Committee the authority to oversee environmental,health and safety issues relating to Generation. The respective Boards of ComEd, PECO and BGE, which each include directors who also serveon the Exelon Board of Directors, oversee environmental, health and safety issues related to ComEd, PECO and BGE. Air Quality Air quality regulations promulgated by the EPA and the various state and local environmental agencies in Illinois, Maryland, Massachusetts,New York, Pennsylvania and Texas in accordance with the Federal Clean Air Act impose restrictions on emission of particulates, sulfur dioxide(SO2), nitrogen oxides (NOx), mercury and other pollutants and require permits for operation of emissions sources. Such permits have beenobtained by Exelon’s subsidiaries and must be renewed periodically. The Clean Air Act establishes a comprehensive and complex nationalprogram to substantially reduce 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. 24Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsWater Quality Under the Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the 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 power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculatingsystems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. For Generation, those facilities are CalvertCliffs, Clinton, Dresden, Eddystone, Fairless Hills, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek,Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. On October 14, 2014, the 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 to minimize adverse impacts on aquatic life, followed by an implementation period for theselected technology. The timing of the various requirements for each facility is related to the status of its current NPDES permit and thesubsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director. Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant,Generation cannot estimate the effect that compliance with the rule will have on the operation of its generating facilities and its future results ofoperations, cash flows, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply withthe rule, that facility’s economic viability would be called into question. However, the potential impact of the rule has been significantly reducedsince the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and thestate permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors. New York Facilities. In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the 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. The Ginna and Nine Mile Point Unit 1 power generation facilities received renewals of their state water discharge permits in2014. Salem. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, expiring in July 2006, allowing for the continued operation ofSalem with its existing cooling water system. In February 2006, PSEG filed a renewal application with the NJDEP allowing Salem to continueoperating under its existing NPDES permit until a new permit was issued. On June 30, 2015, NJDEP issued a draft NPDES permit for Salem. Thedraft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling watersystem with certain required system modifications. The draft permit was subject to a public notice and comment period and the NJDEP may makerevisions before issuing the final permit expected during the first half of 2016. 25Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSolid and Hazardous Waste CERCLA provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardoussubstances into the environment and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potentialenvironmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardoussubstances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanupcosts of waste at sites, most of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform acleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanupcosts, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, includingIllinois, Maryland and Pennsylvania, have also enacted statutes that contain provisions substantially similar to CERCLA. In addition, RCRAgoverns treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted. Generation, ComEd, PECO and BGE and their subsidiaries are, or are likely to become, parties to proceedings initiated by the EPA, stateagencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including MGP sites, or may undertake toinvestigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party. See Note 23—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 in2016 at Exelon for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites isexpected to total $38 million, consisting of $32 million and $6 million respectively, at ComEd and PECO. Generation’s environmental liabilities primarily arise from contamination at current and former generation and waste storage facilities. As ofDecember 31, 2015, 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 23—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. 26Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGlobal 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 natural gas-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 2015, 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 fossil fuel generation of electricity used to power itsfacilities. Despite its focus on low-carbon generation, Exelon believes its operations could be significantly affected by the possible physical risksof climate change and by mandatory programs to reduce GHG emissions. See ITEM 1A. RISK FACTORS for information regarding the market andfinancial, regulatory and legislative, and operational risks associated with climate change. Climate Change Regulation. Exelon is, or may become, subject to climate change regulation or legislation at the Federal, regional andstate levels. International Climate Change Regulation. At the international level, the United States is a Party to the United Nations Framework Conventionon Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21session of the UNFCCC Conference of theParties (COP 21) on December 12, 2015. The Paris Agreement defines the UNFCCC’s objective of limiting the global temperature increase to1.5°C above pre-industrial levels. All Parties are required to develop their own national emission reductions and to update those reductions at leastevery five years. The Developed Country Parties, including the United States, are required to take the lead by undertaking economy-wide absoluteemission reduction targets. The United States had previously submitted its national emission reductions to achieve a 2020 target of reducing netemissions in the range of 17% below the 2005 level and to achieve net greenhouse gas emission reductions of 26%—28% below the 2005 level by2025. The United States has indicated that it intends to achieve these reductions through a variety of mechanisms, including regulations to cutcarbon pollution from new and existing power plants. The Paris Agreement will enter into force on the thirtieth day after the date on which at least55 Parties accounting for at least an estimated 55% of total global greenhouse gas emissions have ratified the Agreement. Federal Climate Change Legislation and Regulation. It is highly uncertain that Federal legislation to reduce GHG emissions will be enacted. Ifsuch legislation is adopted, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emissionallowances or credits. In June 2013, the White House released the President’s Climate Action Plan which consists of a wide variety of executiveactions targeting GHG reductions, preparing for the impacts of climate change and showing leadership internationally; but the plan did not directlytrigger any new requirements or legislative action. The EPA is addressing the issue of carbon dioxide (CO) emissions regulation for new and existing electric generating units through the NewSource Performance Standards (NSPS) under 27st 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSection 111 of the Clean Air Act. Pursuant to the Climate Action Plan, President Obama directed the EPA to regulate new and modified fossil firedgenerating units under Section 111(b) of the Clean Air Act. The EPA finalized the rule in August 2015, and the final rule has been challenged in theU.S. Court of Appeals for the District of Columbia. Under the President’s memorandum, the EPA was also required to finalize a rule to establish CO emission reduction requirements forexisting fossil-fuel generating stations under Section 111(d) of the Clean Air Act. The final rule, known as the Clean Power Plan, became effectiveon December 22, 2015. The rule sets GHG emission reduction targets for each state, with reductions beginning in 2022, and the target achievedby 2030. States must submit an implementation plan to the EPA by September 2016, unless granted an extension of up to two years. States aregranted latitude to select from a number of compliance options, which are designed to achieve the reductions in the most cost-effective manner.The final rule has been challenged in the U.S. Court of Appeals for the District of Columbia. On February 9, 2015, the U.S. Supreme Court issueda stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions arefiled in the future, before the U.S. Supreme Court. While the ultimate impact of the Clean Power Plan rule is expected to be favorable, Exelon andGeneration cannot at this time predict to what extent the states’ actions to comply with the Clean Power Plan’s emission reduction targets willimpact their future financial position, results of operations and cash flows. 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 from 2015 through 2020. Included inthe 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 available for purchase at auction. (CCR trigger prices are $6 in 2015, $8 in 2016 and$10 in 2017; after 2017 the CCR price increases by 2.5 percent each year). Such an outcome could put modest upward pressure on wholesalepower prices; however, the specifics are currently uncertain. At the state level, the Illinois Climate Change Advisory Group, created by Executive Order 2006-11 on October 5, 2006, made its 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 greenhouse gas reduction strategy with 42recommendations on August 27, 2008. The plan’s primary policy recommendation to formally adopt science-based regulatory goals to reduceMaryland’s GHG emissions was realized with the passage of the Greenhouse Gas Emissions Reduction Act of 2009 (GGRA) which requiresMaryland to reduce its GHG emissions by 25 percent below 2006 levels by 2020. It also directed the Maryland Department of Environment toprepare and implement an action plan which was published in October of 2013. Maryland’s electricity consumption reduction goals, required underthe “EmPOWER Maryland” program, and mandatory State participation in RGGI Program, are listed as the energy sector’s contribution in the plan.The plan also advocated raising the renewable portfolio standard requirement from 20% by 2022 to 25% by 2022. The Department of Environmentwas required to submit a December 2015 report to the Governor and General Assembly 28222Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 progress towards the 25% mandate; its costs and benefits; the need for target adjustments; and the status of federal programs. In 2016, theLegislature will review the progress report, its economic impacts on manufacturing sector and other information and determine whether to continue,adjust or eliminate the requirement to achieve a 25% reduction by 2020. Exelon’s Voluntary Climate Change Efforts. In a world increasingly concerned about global climate change and regulatory action to 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. 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. 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 tocumulatively increase this percentage to at least 10% by June 1, 2015 and 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, 2015, 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. The AEPS Act became effective for PECO on January 1, 2011. During 2015, PECO was required to supply approximately 5.0% of electricenergy generated from Tier I alternative energy resources (including solar, wind power, low-impact hydropower, geothermal energy, biologicallyderived methane gas, fuel cells, biomass energy, coal mine methane and black liquor generated within Pennsylvania), as measured in AECs,through May 31, 2015 and subsequently 5.5% beginning June 1, 2015 and continuing through May 31, 2016. PECO was also required to supply6.2% of electric energy generated from Tier II alternative energy resources (including waste coal, demand-side management, large-scalehydropower, municipal solid waste, generation of electricity utilizing wood and by-products of the pulping process and wood, distributed generationsystems and integrated combined coal gasification technology), as measured in AECs, through May 31, 2015 and subsequently 8.2% beginningJune 1, 2015 and continuing through May 31, 2016. The compliance requirements will incrementally escalate to 8.0% for Tier I and 10.0% for TierII by 2021. In order to comply with these requirements, PECO entered into agreements with varying terms with accepted bidders, includingGeneration, to purchase non-solar Tier I, solar Tier 1 and Tier II AECs. PECO also purchases AECs through its DSP Program full requirementcontracts. 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 29Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentssources (hydroelectric, other than pump storage generation, and waste-to-energy). The RPS requirement began in 2006, requiring that suppliersprocure 1.0% and 2.5% from Tier 1 and Tier 2 sources, respectively, escalating in 2022 to 22.0% from Tier 1 sources, including at least 2.0% fromsolar energy, and a phase out of Tier 2 resource options by 2022. In 2015, 10.5% was required from Tier 1 renewable sources, including at least0.5% derived from solar energy and 2.5% from Tier 2 renewable sources. BGE is subject to requirements established by the Public Utilities Articlein Maryland related to the use of alternative energy resources; however, the wholesale suppliers that supply power to BGE through SOSprocurement auctions have the obligation, by contract with BGE, to meet the RPS requirements. Similar to ComEd, PECO and BGE, Generation’s retail electric business must source a portion of the electric load it serves in many of 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 of the Combined Notes to Consolidated Financial Statements for additional information. Executive Officers of the Registrants as of February 10, 2016 Exelon Name Age Position PeriodCrane, Christopher M. 57 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. 50 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. 55 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. 57 Chief Executive Officer, ComEd 2012 - Present President, ComEd 2009 - Present Chief Operating Officer, ComEd 2009 - 2012 30Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 PeriodAdams, Craig L. 63 President and Chief Executive Officer, PECO 2012 - Present Senior Vice President and Chief Operating Officer, PECO 2007 - 2012Butler, Calvin G. 46 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. 62 Senior Executive Vice President and Chief Strategy Officer, Exelon 2012 - Present Executive Vice President, Finance and Legal, Exelon 2009 - 2012Thayer, Jonathan W. 44 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 53 Executive Vice President and Chief Enterprise Risk Officer, Exelon 2013 - Present Managing Director, Gleam Capital Management 2012 - 2013 Principal and Managing Director, Gunvor International 2009 - 2011DesParte, Duane M. 52 Senior Vice President and Corporate Controller, Exelon 2008 - Present Generation Name Age Position PeriodCornew, Kenneth W. 50 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 51 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. 55 Executive Vice President and Chief Operating Officer, Exelon Generation 2015 - Present President, Exelon Nuclear; Senior Vice President and Chief Nuclear Officer,Generation 2010 - 2015 Chief Operating Officer, Exelon Nuclear 2007 - 2010 31Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 PeriodHanson, Bryan C. 50 President and Chief Nuclear Officer, Exelon Nuclear; Senior VicePresident, 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 53 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. 49 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 49 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 ComEd Name Age Position PeriodPramaggiore, Anne R. 57 Chief Executive Officer, ComEd 2012 - Present President, ComEd 2009 - Present Chief Operating Officer, ComEd 2009 - 2012Donnelly, Terence R. 55 Executive Vice President and Chief Operating Officer, ComEd 2012 - Present Executive Vice President, Operations, ComEd 2009 - 2012Trpik Jr., Joseph R. 46 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. 53 Senior Vice President, Regulatory and Energy Policy and General Counsel,ComEd 2010 - Present Senior Vice President, Exelon 2009 - 2010Marquez Jr., Fidel 54 Senior Vice President, Governmental and External Affairs, ComEd 2012 - Present Senior Vice President, Customer Operations, ComEd 2009 - 2012 32Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 PeriodBrookins, Kevin B. 54 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 51 Senior Vice President, Distribution Operations, ComEd 2010 - Present Vice President, Transmission and Substations, ComEd 2007 - 2010Kozel, Gerald J. 43 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. 63 President and Chief Executive Officer, PECO 2012 - Present Senior Vice President and Chief Operating Officer, PECO 2007 - 2012Barnett, Phillip S. 52 Senior Vice President and Chief Financial Officer, PECO 2007 - Present Treasurer, PECO 2012 - PresentInnocenzo, Michael A. 50 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 - 2010Webster Jr., Richard G. 54 Vice President, Regulatory Policy and Strategy, PECO 2012 - Present Director of Rates and Regulatory Affairs 2007 - 2012Murphy, Elizabeth A. 56 Vice President, Governmental and External Affairs, PECO 2012 - Present Director, Governmental & External Affairs, PECO 2007 - 2012Jiruska, Frank J. 55 Vice President, Customer Operations, PECO 2013 - Present Director of Energy and Marketing Services, PECO 2010 - 2013Diaz Jr., Romulo L. 69 Vice President and General Counsel, PECO 2012 - Present Vice President, Governmental and External Affairs, PECO 2009 - 2012Bailey, Scott A. 39 Vice President and Controller, PECO 2012 - Present Assistant Controller, Generation 2011 - 2012 Director of Accounting, Power Team 2007 - 2011 33Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Name Age Position PeriodButler, Calvin G. 46 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. 48 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. 43 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. 54 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 - 2011Gahagan, Daniel P. 62 Vice President and General Counsel, BGE 2007 - PresentBauer, Matthew N. 39 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 - 2012Núñez, Alexander G. 44 Vice President, Governmental and External Affairs, BGE 2013 - Present Director, State Affairs, BGE 2012 - 2013 Director, State Affairs, Constellation Energy 2006 - 2012 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 Enterprise Risk Officer and the RMC, which comprises officersof the Registrants, to identify and evaluate the most significant risks of the Registrants’ businesses, and the appropriate steps to manage andmitigate those risks. The Chief Enterprise Risk Officer and senior executives of the Registrants discuss those risks with the finance and riskcommittee and audit committee of the Exelon board of directors and the ComEd, PECO and BGE boards of directors. In addition, the 34Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 oversight committee of the Exelon board of directors evaluates risks related to the generation business. The risk factors discussedbelow could adversely affect one or more of the Registrants’ results of operations or cash flows and the market prices of their publicly tradedsecurities. Each of the Registrants has disclosed the known material risks that affect its business at this time. However, there may be furtherrisks and uncertainties that are not presently known or that are not currently believed by a Registrant to be material that could adversely affect itsperformance or financial condition in the future. Exelon’s financial conditions 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 affect the Registrants include changes to the laws andregulations that govern competitive markets and utility cost recovery, and that drive environmental policy. In particular, Exelon’s andGeneration’s financial performance could 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. • 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 could negatively affect its results ofoperations or 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. 35Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsPrice 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 programscould each 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, could often exceed demand during some hours of the day, resulting in loss of revenuefor base-load generating plants. Increased supply in excess of demand is furthered by the continuation of RPS mandates and subsidies forrenewable energy. 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 wholesale generators (including Generation)use their retail operations to hedge generation output. Increased or more aggressive competition could adversely affect overall gross margins andprofitability in Generation’s retail operations. Sustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s results of operations orcash flows, and such impacts could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily twogeographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s ability tofund 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 result of operations through accelerateddepreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capitalprojects, accelerated amortization of plant specific nuclear fuel costs, severance costs, accelerated asset retirement obligation expense relate tofuture decommissioning activities, and additional funding of decommissioning costs, which can be offset in whole or in part by reduced operatingand maintenance expenses. A slow recovery in market conditions could result in a prolonged depression of or further decline in commodity prices,including low forward natural gas and power prices and low market volatility, which could also adversely affect Exelon’s and Generation’s results ofoperations, cash flows or financial positions. See Note 9—Implications of Potential Early Plant Retirements of the Combined Notes toConsolidated Financial Statements for additional information. 36Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 to price fluctuations, Generation is exposed to other risks in the power markets that are beyond its control and couldnegatively 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 could 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 could be incurred due to the nonpayment of acustomer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer. Market Designs. The wholesale markets remain evolving markets that vary from region to region and are still developing rules, practices 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 could 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, distributed generation and energy storage devices. Such developments could affectthe price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvementsto our distribution systems to address changing load demands and could make portions of our electric system power supply and transmissionand/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodityprices or demand for delivered energy. Each of these factors could materially affect the Registrants’ results of operations, cash flows or financialpositions through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capitalexpenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remainingasset useful lives. Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could 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 could 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 could fall below the Registrants’ projected return rates. A decline in the marketvalue of the NDT fund investments could increase Generation’s funding requirements to decommission its nuclear plants. A decline in the 37Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsmarket value of the pension and OPEB plan assets will increase the funding requirements associated with Exelon’s pension and OPEB planobligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, theliabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers ofretirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase thecosts and funding requirements of the obligations related to the pension and OPEB plans. If future increases in pension and other postretirementcosts as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from ComEd, PECO andBGE customers, the results of operations and financial positions of ComEd, PECO and BGE could be negatively affected. Ultimately, if theRegistrants are unable to manage the investments within the NDT funds and benefit plan assets, and are unable to manage the related benefit planliabilities, their results of operations, cash flows or financial positions could be negatively impacted. Unstable capital and credit markets and increased volatility in commodity markets could 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 negatively impact the Registrants’ results of operations, cash flows or financial positions. (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 could 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 regulation, reduced alternatives or failures ofsignificant financial institutions could result in the deferral of discretionary capital expenditures, changes to Generation’s hedging strategy in orderto reduce collateral-posting requirements, or a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe. Disruptions in the European markets couldreduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2015,approximately 25%, or $2.1 billion of the Registrants’ available credit facilities were with European banks. The credit facilities include $8.4 billion inaggregate total commitments of which $6.9 billion was available as of December 31, 2015. There were no borrowings under the Registrants’ creditfacilities as of December 31, 2015. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements foradditional 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 38Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with othermechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on Exelon’s andGeneration’s results of operations or 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 could 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.Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings.Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specificproject being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made,the lenders or security holders would generally have rights to foreclose against the project assets and related collateral. 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 could have a material adverse effect upon their liquidity. Collateral posting requirements willgenerally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO and BGE, with respect totheir natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. Given therelationship to forward market prices, contract collateral requirements can be volatile. In addition, if ComEd, PECO and BGE were downgraded,they could experience higher borrowing costs as a result of the downgrade. ComEd, PECO or BGE could experience a downgrade in its ratings if any of the credit rating agencies conclude that the level of business orfinancial risk and overall creditworthiness of the utility industry in general, or ComEd, PECO, or BGE in particular, has deteriorated. ComEd, PECOor BGE could experience a downgrade if the current regulatory environments in Illinois, Pennsylvania or Maryland, respectively, become lesspredictable by materially lowering returns for utilities in the applicable state or adopting other measures to limit electricity prices. Additionally, theratings for ComEd, PECO or BGE could be downgraded if their financial results are weakened from current levels due to weaker operatingperformance or due to a failure to properly manage their capital structure. In addition, changes in ratings methodologies by the agencies could alsohave a negative impact on the ratings of ComEd, PECO or BGE. 39Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 could 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 supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuelfabrication services. Natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supplymarkets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that could negativelyaffect the results of operations or 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 and cannot eliminate all risksassociated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimatesof future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to beincorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and thecalculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that itscommodity trading activities and risk management decisions could have on its business, operating results, cash flows or financial positions. 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 could expose Generation to volatility infuture results of operations. Financial performance and load requirements could be adversely affected if Generation is unable to effectively manage its powerportfolio. (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 40Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsare not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient tomeet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets.Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manageits 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 or 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 could be on its results ofoperations or 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 13, 2013 to initiate litigation inthe United States Tax Court and the trial took place in August 2015. Exelon was not required to remit any part of the asserted tax or penalty inorder to litigate the like-kind exchange position. The litigation could take three to five years including appeals, if necessary. As of December 31, 2015, 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 $760 million, of whichapproximately $280 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 approximately $90 million of penalties for a substantialunderstatement of tax. The timing effects of the final resolution of the like-kind exchange matter are unknown. See Note 15—Income Taxes of theCombined Notes to Consolidated Financial Statements for additional information. Tax reserves. The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These taxobligations include income, real estate, sales and use and employment-related taxes and ongoing appeals issues related to these tax matters.These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken that could be subject to challengeby the tax authorities. See Notes 1—Significant Accounting Policies and Note 15—Income Taxes of the Combined Notes to ConsolidatedFinancial Statements for additional information. Increases in customer rates and the impact of economic downturns could lead to greater expense for uncollectible customer balances.Additionally, increased rates could lead to decreased volumes delivered. Both of these factors could decrease Generation’s, ComEd’s,PECO’s and BGE’s results from operations or 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 41Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsbetween shareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantlyhigher rates related to purchased power and natural gas could result in declines in customer usage, lower revenues and potentially additionaluncollectible accounts expense for ComEd, PECO and BGE. In addition, any challenges by the regulators or ComEd, PECO and BGE as to therecoverability of these costs could have a material effect on the Registrants’ results of operations or cash flows. Also, ComEd’s, PECO’s andBGE’s cash flows could be affected by differences between the time period when electricity and natural gas are purchased and the ultimaterecovery from customers. 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, could result in an increase in the number of uncollectiblecustomer balances, which would negatively impact ComEd’s, PECO’s and BGE’s results of operations or cash flows. Generation’s customer-facing energy delivery activities face economic downturn risks similar to Exelon’s utility businesses, such as lower volumes sold and increasedexpense for uncollectible customer balances. As Generation increases its customer-facing energy delivery activities, economic downturn impactscould negatively affect Generation’s results of operations or cash flows. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURESABOUT MARKET RISK for further discussion of the Registrants’ credit risk. The effects of weather could impact the Registrants’ results of operations or cash flows. (Exelon, Generation, ComEd, PECO and BGE) Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperaturesabove normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels inthe winter tend to increase winter heating electricity and gas demand and revenues. 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 actual distribution volumes are for a billing period, and is not affected by actual weather with the exception of major storms.Extreme weather conditions or damage resulting from storms could stress ComEd’s, PECO’s and BGE’s transmission and distribution systems,communication systems and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peakcustomer demand. These extreme conditions could have detrimental effects on ComEd’s, PECO’s and BGE’s results of operations or cash flows.First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons lessrelevant. 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 could require greater resources to meet its contractualcommitments. Extreme weather conditions or storms could 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 could impact Generation’s ability to run certaingenerating assets at full capacity. These conditions, which cannot be accurately predicted, could 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. 42Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 long-lived assets and other assets recorded on the Registrants’ statements of financial position could 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 positions. Specifically, long-lived assetsaccount for 60%, 56%, 66%, 69% and 80% of total assets for Exelon, Generation, ComEd, PECO and BGE, respectively, as of December 31,2015. In addition, Exelon and Generation have significant balances related to unamortized energy contracts. See Note 11—Intangible Assets ofthe Combined Notes to Consolidated Financial Statements for additional information on Exelon’s unamortized energy contracts. The Registrantsevaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potentialimpairment exist. Factors such as the business climate, including current and future energy and market conditions, environmental regulation, andthe condition of assets are considered when evaluating long-lived assets for potential impairment. An impairment would require the Registrants toreduce the carrying value of the long-lived asset through a non-cash charge to expense by the amount of the impairment, and such an impairmentcould 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, 2015 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 Exelon’s andComEd’s like-kind exchange income tax position, adverse regulatory actions such as early termination of EIMA, or changes in significantassumptions used in estimating ComEd’s fair value (e.g., discount and growth rates, utility sector market performance and transactions, operatingand capital expenditure requirements and the fair value of debt) could result in an impairment. Such an impairment would result in a non-cashcharge 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 11—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 could 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 43Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsdistribution infrastructure projects. These operational systems and infrastructure have been in service for many years. Equipment, even ifmaintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, andcould require significant expenditures to operate efficiently. The Registrants’ results of operations, financial conditions, or cash flows could beadversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. Furthermore, operational failure ofelectric or gas systems or infrastructure could result in potential liability if such failure results in damage to property or injury to individuals. SeeITEM 1. BUSINESS for further information regarding the Registrants’ potential future capital expenditures. Exelon and its subsidiaries have guaranteed the performance of third parties, which could 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 could 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 conditions, 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 or financial positions. 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 could 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 restructuring. 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 or financial positions. Regulatory and Legislative Factors The Registrants’ generation and energy delivery businesses are highly regulated and could be subject to regulatory and legislativeactions that adversely affect their operations or financial results. Fundamental changes in regulation or legislation or violation of tariffsor market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations orfinancial 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. 44Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsSimilarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certaintransactions. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses andchanges in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxingauthorities. Additionally, the Registrants need to be cognizant and understand rule changes or Registrant actions that could result in potentialviolation of tariffs, market rules and anti-manipulation laws. Fundamental changes in regulations or other adverse legislative actions affecting theRegistrants’ businesses would require changes in their business planning models and operations and could negatively impact their results ofoperations, cash flows or financial positions. Regulatory and legislative developments related to climate change and RPS could also significantly affect Exelon’s and Generation’s resultsof operations, cash flows or 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 an RPS could alsoincrease the pace of development of wind energy facilities in the Midwest, which could put downward pressure on wholesale market prices forelectricity from Generation’s Midwest nuclear assets, partially offsetting any additional value Exelon and Generation might derive fromGeneration’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 could 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 65% 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. 45Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 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. 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, incentives toshift 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 lesserdegree 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 accepts 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 46Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, or BGE, with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. Theprospect of such challenges may increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of suchchallenges may subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, governmentofficials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, throughmeasures such as generation-based taxes and contributions to rate-relief packages. The Registrants could 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 handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements could subjectthe Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediationand clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achievecompliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination ofproperty now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants haveincurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activitiesassociated with MGP operations conducted by predecessor companies are one component of such costs. Also, 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. 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. On June 30, 2015, NJDEP issued a draft NPDES permit for Salem. The draft permit does not requireinstallation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The draft permit issubject to a public notice and comment period after which the NJDEP may make revisions before issuing the final permit expected during the firsthalf of 2016. 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 could 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 23—Commitments and Contingencies of the Combined Notes to Consolidated FinancialStatements for additional information. 47Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 could 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 couldbe 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. In 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 default service obligations, referred to as POLR, DSP and SOSfor ComEd, PECO and BGE, respectively, to provide electricity and natural gas to certain groups of customers in their respective service areaswho do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability ofComEd, PECO and BGE, as applicable, to recover their costs and could have a material adverse effect on ComEd’s, PECO’s and BGE’s resultsof operations, cash flows and financial position. See Note 3—Regulatory Matters of the Combined Notes to the Consolidated Financial Statementsfor 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 or 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 48Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentslead 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, 2015, 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 andComprehensive Income. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements ofExelon, ComEd, PECO and BGE. At December 31, 2015, the gain (loss) could have been as much as $(2.5) billion, $978 million and $559 million(before taxes) as a result of the elimination of ComEd’s, PECO’s and BGE’s regulatory assets and liabilities, respectively. Further, Exelon wouldrecord a charge against OCI (before taxes) of up to $2.5 billion and $634 million for ComEd and BGE, respectively, related to Exelon’s netregulatory assets associated with its defined benefit postretirement plans. Exelon also has a net regulatory liability of $47 million (before taxes)associated with PECO’s defined benefit postretirement plans that would result in an increase in OCI if reversed. The impacts and resolution of theabove items could lead to an additional impairment of ComEd’s goodwill, which could be significant and at least partially offset the gain at ComEddiscussed above. A significant decrease in equity as a result of any changes could limit the ability of ComEd, PECO and BGE to pay dividendsunder Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in future results ofoperations. See Notes 1—Significant Accounting Policies, 3—Regulatory Matters and 11—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 could 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 23—Commitments and Contingencies of the CombinedNotes to Consolidated Financial Statements. 49Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 could subject the Registrants to higher operating costs and/orincreased capital expenditures. In addition, the ICC, PAPUC and MDPSC impose certain distribution reliability standards on ComEd, PECO andBGE, respectively. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject toremediation costs as well as sanctions, which could include substantial monetary penalties. ComEd, PECO and BGE as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmissionowners regarding assessments of transmission lines. The results of these assessments could require ComEd, PECO and BGE to incurincremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. See Note 3—Regulatory Matters and Note 23—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 couldnegatively impact their results of operations, cash flows or financial positions. (Exelon, Generation, ComEd, PECO and BGE) The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of whichare summarized in Note 23—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 could 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 could require a substantial increase in capitalexpenditures or could result in increased operating or decommissioning costs and significantly affect Generation’s results of operations or financialpositions. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions. 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 significantly affect the costs associated with storage of SNF, and the ultimateamounts received from the DOE to reimburse Generation for these costs. The NRC’s temporary storage rule (also referred to as the “wasteconfidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear power plants for up to 60 years beyond the originaland renewed licensed operating life of the plants. 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 50Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsenvironmental review to support the rule. On September 19, 2014, the NRC issued a revised rule codifying the NRC’s generic determinationsregarding the environmental impacts of continued storage of spent nuclear fuel beyond a reactor’s licensed operating life. The Continued StorageRule became effective on October 20, 2014. Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability todecommission fully its nuclear units. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generationpaid the DOE a fee per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the United States Court of Appeals forthe District of Columbia Circuit ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and untilthere is a viable disposal program. On January 3, 2014, the DOE filed a petition for rehearing which was denied by the D.C. Circuit Court onMarch 18, 2014. Also, on January 3, 2014, the DOE submitted a proposal to Congress to reduce the current SNF disposal fee to zero. On May 9,2014, the DOE notified Generation that the SNF disposal fee was set to zero, effective May 16, 2014. Until such time as a new fee structure is ineffect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. Generation currently estimates 2025 to be the earliestdate when the DOE will begin accepting SNF, which could be delayed by further regulatory action. See Note 23—Commitments and Contingenciesof the Combined Notes to Consolidated Financial Statements for additional information on the spent nuclear fuel obligation. Generation cannotpredict what, if any, fee will be established in the future for SNF disposal. However, such a fee could be material to Generation’s results ofoperations or cash 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 could lose revenue and incur increased fuel and purchased powerexpense to meet supply commitments. Operational Factors The Registrants’ employees, contractors, customers and the general public could 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 could 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. Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact the Registrants’results of operations, its ability to raise capital and its future growth. (Exelon, Generation, ComEd, PECO and BGE) Generation’s fleet of power plants and ComEd’s, PECO’s and BGE’s distribution and transmission infrastructures could be affected 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 51Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsdisasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within theRegistrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and polesor damage to other operating equipment. An example of such an event was the February 5, 2014 ice storm, which interrupted electric servicedelivery to customers in PECO’s service territory and resulted in significant restoration costs. Another example of such an event includes the 9.0 magnitude earthquake and ensuing tsunami experienced by Japan on March 11, 2011,that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. 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 could affect their operations in unpredictable ways, such as changes in insurance markets and disruptionsof fuel 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 could damage or destroy assets or interrupt operations. However, there can be noassurance that the amount of insurance will be adequate to address such property and casualty losses. Generation’s financial performance could 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 52Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsfactors increase Generation’s operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchaseadditional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including ComEd,PECO and BGE. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations. Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refuelingoutages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer thananticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energyreplacement costs and/or lower energy sales. Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could 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 could require significant time andexpense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In eitherevent, Generation could 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 could 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 positions. 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 could 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, could exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recoveredfrom insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect on Generation’s results of operationsor financial positions. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, owned by others orGeneration, could result in increased regulation and reduced public support for nuclear-fueled energy and significantly affect Generation’s results ofoperations or financial positions. 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 $13.5 billion limit for a single incident. 53Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 23—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 units that have been retired and units that are within five years of retirement) addressing Generation’sability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on the decommissioning trust funds. The NRCfunding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit. Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actualresults may differ significantly from current estimates. The performance of capital markets also could significantly affect the value of the trustfunds. Currently, Generation is making contributions to certain trust funds of the former PECO units based on amounts being collected by PECOfrom its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECOcustomers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its othernuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable tocontinue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation nolonger had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of thetrust funds related to the former PECO units could be negatively affected and Exelon’s and Generation’s results of operations or financial positionscould 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 or financial positions could 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 could have to seek remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. Generation’s financial performance could 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 September 1, 2016, and the license for theMuddy Run Pumped Storage Project expires on December 1, 2055. FERC is required to issue annual licenses for the facilities until a finaldetermination is made on the license renewal. Generation cannot predict whether it will receive all the regulatory approvals for the renewedlicenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot beoperated through the end of its operating license, Generation’s results of operations could 54Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsbe adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates anddecommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incurincreased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewalprocess that could adversely affect operations, could require a substantial increase in capital expenditures or could result in increased operatingcosts and significantly affect Generation’s results of operations or financial positions. Similar effects could result from a change in the FederalPower Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation. ComEd’s, PECO’s and BGE’s operating costs, and customers’ and regulators’ opinions of ComEd, PECO and BGE, respectively, 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 could 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’sresults of operations, cash flows or financial conditions could be negatively impacted. 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 negatively impacted. 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 negatively impacted. 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, could affect customer satisfaction and thelevel of regulatory oversight and ComEd’s, PECO’s and BGE’s maintenance and capital expenditures. Regulated utilities, which are required toprovide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relatingto failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involvingextended outages affecting large numbers of its customers, and those damages could be material to ComEd’s results of operations or cash flows.See Note 23—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. ComEd’s, PECO’s and BGE’s respective ability to deliver electricity, their operating costs and their capital expenditures could benegatively impacted 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. 55Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 are subject to physical security and cybersecurity risks. (Exelon, Generation, ComEd, PECO and BGE) The Registrants face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilitiesand as a participant in commodities trading. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utilityindustry associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures, and such attacksand disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digitaltechnologies increase the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of theRegistrants, their competitors, interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/orreliability of the transmission and distribution system or subject the Registrants to financial harm associated with theft or inappropriate release ofcertain types of information, including sensitive customer, vendor, employee, trading or other confidential data. The risk of these system-relatedevents and security breaches occurring continues to intensify, and while we have been, and will likely continue to be, subjected to physical andcyber-attacks, to date we have not experienced a material breach or disruption to our network or information systems or our service operations.However, as such attacks continue to increase in sophistication and frequency, we may be unable to prevent all such attacks in the future. If asignificant breach occurred, the reputation of Exelon and its customer supply activities may be adversely affected, customer confidence in theRegistrants or others in the industry may be diminished, or Exelon and its subsidiaries may be subject to legal claims, any of which maycontribute to the loss of customers and have a negative impact on the business and/or results of operations. Moreover, the amount and scope ofinsurance we maintain against losses resulting from any such events or security breaches may not be sufficient to cover our losses or otherwiseadequately compensate us for any disruptions to our business that may result. ComEd’s, PECO’s and BGE’s deployment of smart metersthroughout their service territories may increase the risk of damage from an intentional disruption of the system by third parties. In addition, new orupdated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their businessoperations and could adversely affect their results of operations, cash flows and financial position. Failure to attract and retain an appropriately qualified workforce could 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, could 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, could arise. The Registrants are particularly affected due to the specialized knowledge required of thetechnical and support employees for their generation, transmission and distribution operations. If the Registrants are unable to successfully attractand retain an appropriately qualified workforce, their results of operations could be negatively impacted. The Registrants could make investments in new business initiatives, including initiatives mandated by regulators, and markets that maynot be successful, and acquisitions could 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 56Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsliquefied natural gas. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations,inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market.As these markets mature, there could be new market entrants or expansion by established competitors that increase competition for customersand resources. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on suchtransactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns oninvestment. 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, cybersecurity 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 could encounter difficulties in satisfying the conditions for the completion of the Merger and the Merger could 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 receipt of regulatoryapprovals required to consummate the Merger, (2) the expiration or termination of the applicable waiting period under the HSR Act and (3) othercustomary closing conditions, including (a) the accuracy of each party’s representations and warranties (subject to customary materialityqualifiers) and (b) each party’s compliance with its obligations and covenants contained in the Merger Agreement. In addition, the obligation ofExelon to consummate the Merger is subject to the required regulatory approvals not, individually or in the aggregate, imposing terms, conditions,obligations or commitments that constitute a burdensome condition (as defined in the Merger Agreement). In addition, the Merger Agreement provides that either Exelon or PHI could terminate the Merger Agreement if the merger is not completedby October 28, 2015. Exelon and PHI have agreed, among other things, that they will not exercise their rights to terminate the Merger Agreementbefore March 4, 2016, except under limited circumstances. 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 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 variousregulatory authorities, including the DCPSC and the public utility commissions or similar entities in certain states in which the companies operate.The Merger has been approved by the Delaware Public Service Commission (DPSC), the Maryland Public Service Commission (MDPSC), the NewJersey Board of Public Utilities (NJBPU) and the Virginia State Corporation Commission. Approval of the Merger by the MDPSC is subject toappeals by the Maryland Office of People’s Counsel, the Sierra Club/Chesapeake Climate Action Network and Public Citizen, Inc. in the CircuitCourt of Queen Anne’s County, and the approval by the NJBPU expires on June 30, 2016. The HSR Act waiting period applicable to the Mergerexpired on December 2, 2015. The Merger remains subject to approval by the DCPSC. See Note 4—Mergers, Acquisitions, and Dispositions of theCombined Notes to Consolidated Financial Statements for additional information regarding the status of regulatory approvals. 57Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 have proposed conditions for approval in the filings that have been made with the DCPSC and other regulatorycommissions. The conditions of approval of the Merger by the DCPSC will trigger the “most favored nation” provisions in the approvals of theMerger by the DPSC, MDPSC, and the NJBPU. 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 unacceptable. The Merger Agreement generally permits Exelon to terminate the MergerAgreement if the final terms of any of the required regulatory consents or approvals include burdensome conditions (as defined in the MergerAgreement). Failure to obtain regulatory approval could 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 $180 million, which would occur by means of PHI’s election to redeem the outstandingnonvoting preferred securities purchased by Exelon in connection with the execution of the Merger Agreement for no consideration other than thenominal par value of the stock. In these circumstances, Exelon will also be required to reimburse PHI for up to $40 million of its documented out-of-pocket expenses for the Merger. Failure to complete the Merger could negatively impact the share price and the future business and financial results of Exelon. If the Merger is not completed, the ongoing businesses of Exelon could be negatively impacted 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 a termination fee ofup to $180 million payable by Exelon to PHI under certain circumstances; and • the share price of Exelon could 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 non-recurring costs associated with combining the operations of the two companies. Mostof these costs will be transaction costs, including fees paid to financial and legal advisors related to the Merger and related financingarrangements, and employment-related costs, including change-in- control related payments made to certain PHI executives. In addition, until theclosing of the Merger, Exelon will be required to pay financing costs without having realized any benefits from the Merger during the period ofdelay. Exelon will also incur transition costs related to formulating integration plans. Exelon expects that the elimination of costs, as well as therealization of other efficiencies related to the integration of the businesses, will exceed incremental transaction and Merger-related costs over time. 58Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 may not realize all the expected benefits of the Merger because of integration difficulties. 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 could 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; and • difficulties in retention of key employees. Exelon and PHI will be subject to various uncertainties while the Merger is pending that could negatively impact their ability to attractand retain key employees, and potentially impact the company’s financial results. Uncertainty about the effect of the Merger on employees, suppliers and customers could have a negative impact on Exelon and/or PHI.These uncertainties could impair Exelon’s and/or PHI’s ability to attract, retain and motivate key personnel until the Merger is completed and for aperiod of time thereafter, as employees and prospective employees could experience uncertainty about their future roles with the combinedcompany. In addition, current and prospective Exelon and PHI employees could determine that they do not desire to work for the combinedcompany for a variety of possible reasons. Moreover, the pendency of Merger regulatory-review proceedings has caused PHI to delay filing baserate cases on behalf of its utilities Pepco, ACE and Delmarva which have had a material impact to their results of operations and cash flows. The Merger could 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 could 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. Exelon is obligated to complete the Merger whether or not it has obtained the required financing. Exelon intended to fund the cash consideration in the Merger using a combination of debt, cash from asset sales, the issuance of equity(including mandatory convertible securities). See Note 4—Mergers, Acquisitions, and Dispositions and Note 14—Debt and Credit Agreements ofthe Combined Notes to Consolidated Financial Statements for additional information regarding the merger financing. Although Exelon had sufficientcash to fund the cash consideration in the Merger as of September 30, 2015, a $2.75 billion portion of the debt incurred to finance the cashconsideration was subject to mandatory special redemption on December 31, 2015. On December 2, 2015, the holders of $1.9 billion of that debtexchanged those debt securities for new notes that extend the mandatory special redemption date from December 31, 2015 to June 30, 2016 (orlater under some circumstances), and on December 2, 2015, Exelon redeemed $868 million of the debt. Exelon could be required to raiseadditional cash to fund the cash consideration in the Merger. 59Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 combined company’s assets, liabilities or results of operations could be negatively impacted 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 negatively impacted 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 negatively impact the combinedcompany’s future business, operating results, cash flows, financial conditions or prospects. Exelon could 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 or financial positions. 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 approximately 90 days after the Merger closing date. If a plaintiff in these or any other litigation claims that may be filed in the future is successful in obtaining an injunction prohibiting the partiesfrom completing the Merger on the terms contemplated by the Merger Agreement, the injunction could 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. 60Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Merger could be completed on terms different from those contained in the Merger Agreement. Prior to the completion of the Merger, Exelon and PHI could, 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 could choose to waive requirements of theMerger Agreement, including some conditions to closing of the Merger. ITEM 1B.UNRESOLVED STAFF COMMENTS Exelon, Generation, ComEd, PECO and BGE None. 61Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015: Station Region Location No. ofUnits PercentOwned PrimaryFuel Type PrimaryDispatchType NetGenerationCapacity (MW) Braidwood Midwest Braidwood, IL 2 Uranium Base-load 2,389 Byron Midwest Byron, IL 2 Uranium Base-load 2,347 LaSalle Midwest Seneca, IL 2 Uranium Base-load 2,320 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 Beebe Midwest Gratiot Co., MI 34 Wind Base-load 82 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 20 Marshall Midwest Lyon Co., MN 9 99 Wind Base-load 19 Norgaard Midwest Lincoln Co., MN 7 99 Wind Base-load 9 City Solar Midwest Chicago, IL 1 Solar 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 Solar Ohio Midwest Toledo, OH 3 Solar Base-load 3 Cowell Midwest Pipestone Co., MN 1 99 Wind Base-load 2 Southeast Chicago Midwest Chicago, IL 8 Gas Peaking 296 Total Midwest 12,163 Limerick Mid-Atlantic Sanatoga, PA 2 Uranium Base-load 2,317 Peach Bottom Mid-Atlantic Delta, PA 2 50 Uranium Base-load 1,299 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 Fair Wind Mid-Atlantic Garrett County, MD 12 Wind Base-load 30 Solar Maryland MC Mid-Atlantic Various, MD 15 Solar Base-load 27 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 10 Solar Base-load 7 Solar Maryland 2 Mid-Atlantic Various, MD 3 Solar Base-load 7 Solar Federal Mid-Atlantic Trenton, NJ 1 Solar Base-load 4 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 Perryman Mid-Atlantic Aberdeen, MD 6 Oil/Gas Peaking 463 Croydon Mid-Atlantic West Bristol, PA 8 Oil Peaking 391 Handsome Lake Mid-Atlantic Kennerdell, PA 5 Gas Peaking 268 Notch Cliff Mid-Atlantic Baltimore, MD 8 Gas Peaking 118 Westport Mid-Atlantic Baltimore, MD 1 Gas Peaking 116 Riverside Mid-Atlantic Baltimore, MD 3 Oil/Gas Peaking 113 Richmond Mid-Atlantic Philadelphia, PA 2 Oil Peaking 98 62(a)(b)(c)(d)(f)(f)(f)(f)(f)(f)(f)(f)(f)(f)(f)(g)(e)(h)(h)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 5 Total Mid-Atlantic 11,725 Whitetail ERCOT Webb County, TX 57 Wind Base-load 91 Sendero ERCOT Jim Hogg and ZapataCounty, TX 39 Wind Base-load 78 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 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 3,593 Solar Massachusetts New England Various, MA 18 Solar Base-load 8 Holyoke Solar New England Various, MA 2 Solar Base-load 4 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 West 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 2,219 Nine Mile Point New York Scriba, NY 2 50.01 Uranium Base-load 838 Ginna New York Ontario, NY 1 50.01 Uranium Base-load 288 Solar New York New York Bethlehem, NY 1 Solar Base-load 2 Total New York 1,128 AVSR Other Lancaster, CA 1 Solar Base-load 242 Shooting Star Other Kiowa County, 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 34 Solar Arizona Other Various, AZ 55 Solar Base-load 33 Cassia Other Buhl, ID 14 Wind Base-load 29 Wildcat Other Lovington, NM 13 Wind Base-load 27 Sacramento PV Energy Other Sacramento, CA 4 Solar Base-load 26 Sunnyside Other Sunnyside, UT 1 50 Waste Coal Base-load 26 Echo 2 Other Echo, OR 10 Wind Base-load 20 Tuana Springs Other Hagerman, ID 8 Wind Base-load 17 California PV Energy Other Various, CA 37 Solar Base-load 16 Greensburg Other Greensburg, KS 10 Wind Base-load 13 63(a)(b)(c)(d)(f)(f)(f)(g)(f)(g)(f)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Solar Georgia Other Various, GA 14 Solar Base-load 12 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 California Other Various, CA 25 Solar Base-load 10 Outback Solar Other Christmas Valley, OR 1 Solar Base-load 5 Loess Hills Other Rock Port, MO 4 Wind Base-load 5 Mohave Sunrise Solar Other Fort Mohave, AZ 1 Solar Base-load 5 Denver Airport Solar Other Denver, CO 1 Solar Base-load 4 Hillabee Other Alexander City, AL 3 Gas Intermediate 722 Grande Prairie Other Alberta, Canada 1 Gas Peaking 105 SEGS 4, 5, 6 Other Boron, CA 3 4.2-12.2 Solar Peaking 9 Total Other 1,913 Total 32,741 (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 operations at the Perryman 2 (51 MWs) and Riverside 4 (74 MWs) units effective February 1, 2016 and May 31, 2016,respectively. 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. Generation 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. 64(a)(b)(c)(d)(f)(f)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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, 2015 were as follows: Voltage (Volts) Circuit Miles765,000 90345,000 2,656138,000 2,306 ComEd’s electric distribution system includes 35,419 circuit miles of overhead lines and 31,040 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. Transmission and Distribution PECO’s high voltage electric transmission lines owned and in service at December 31, 2015 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. 65(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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’s electric distribution system includes 12,960 circuit miles of overhead lines and 9,218 circuit miles of underground lines. Gas The following table sets forth PECO’s natural gas pipeline miles at December 31, 2015: Pipeline Miles Transmission 30 Distribution 6,826 Service piping 6,220 Total 13,076 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 150 mmcf and a peaking capability of25 mmcf/day. In addition, PECO owns 31 natural gas city gate stations and direct pipeline customer delivery points at various locations throughoutits 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. Transmission and Distribution BGE’s high voltage electric transmission lines owned and in service at December 31, 2015 were as follows: Voltage (Volts) Circuit Miles500,000 218230,000 322138,000 55115,000 703 BGE’s electric distribution system includes 9,190 circuit miles of overhead lines and 16,841 circuit miles of underground lines. 66Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsGas The following table sets forth BGE’s natural gas pipeline miles at December 31, 2015: Pipeline Miles Transmission 161 Distribution 7,173 Service piping 6,225 Total 13,559 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. ITEM 3.LEGAL PROCEEDINGS Exelon, Generation, ComEd, PECO and BGE The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. Forinformation regarding material lawsuits and proceedings, see Note 3—Regulatory Matters and Note 23—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. 67Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2016, there were 919,924,742 shares of commonstock outstanding and approximately 118,487 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: 2015 2014 FourthQuarter ThirdQuarter SecondQuarter FirstQuarter FourthQuarter ThirdQuarter SecondQuarter FirstQuarter High price $31.37 $34.44 $34.98 $38.25 $38.93 $36.26 $37.73 $33.94 Low price 25.09 28.41 31.28 31.71 33.07 30.66 33.11 26.45 Close 27.77 29.70 31.42 33.61 37.08 34.09 36.48 33.56 Dividends 0.310 0.310 0.310 0.310 0.310 0.310 0.310 0.310 68Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2011 through 2015. This performance chart assumes: • $100 invested on December 31, 2010 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, 2010 2011 2012 2013 2014 2015Exelon Corporation $100 $108.67 $78.93 $76.16 $107.03 $83.31S&P 500 $100 $98.88 $112.13 $145.33 $161.88 $160.70S&P Utilities $100 $114.25 $110.93 $120.64 $149.94 $137.36 Generation As of January 31, 2016, Exelon indirectly held the entire membership interest in Generation. ComEd As of January 31, 2016, there were 127,016,973 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904shares were indirectly held by Exelon. At January 31, 2016, in addition to Exelon, there were 299 record holders of ComEd common stock. Thereis no established market for shares of the common stock of ComEd. 69Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2016, 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, 2016, 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 70Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsMDPSC that BGE’s equity ratio is at least 48% within five business days after dividend payment. There are no other limitations on BGE payingcommon stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043,and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE’s preference stock have not been paid. Exelon’s Board of Directors approved a revised dividend policy. The approved policy would raise our dividend 2.5% each year for the nextthree years, beginning with the June 2016 dividend. The Board will take formal action to declare the next dividend in the second quarter. At December 31, 2015, Exelon had retained earnings of $12,068 million, including Generation’s undistributed earnings of $2,701 million,ComEd’s retained earnings of $978 million consisting of retained earnings appropriated for future dividends of $2,617 million, partially offset by$(1,639) million of unappropriated retained deficits, PECO’s retained earnings of $780 million, and BGE’s retained earnings of $1,320 million. The following table sets forth Exelon’s quarterly cash dividends per share paid during 2015 and 2014: 2015 2014 (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 $0.310 The following table sets forth Generation’s quarterly distributions and ComEd’s and PECO’s quarterly common dividend payments: 2015 2014 (in millions) 4thQuarter 3rdQuarter 2ndQuarter 1stQuarter 4thQuarter 3rdQuarter 2ndQuarter 1stQuarter Generation $106 $106 $906 $1,356 $205 $205 $205 $31 ComEd 75 75 75 75 77 77 77 76 PECO 70 70 70 70 80 80 80 80 First Quarter 2016 Dividend. On January 26, 2016, the Exelon Board of Directors declared a first quarter 2016 regular quarterly dividend of$0.31 per share on Exelon’s common stock payable on March 10, 2016, to shareholders of record of Exelon at the end of the day on February 12,2016. 71Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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) 2015 2014 2013 2012 2011 Statement of Operations data: Operating revenues $29,447 $27,429 $24,888 $23,489 $19,063 Operating income 4,409 3,096 3,669 2,373 4,479 Income from continuing operations 2,250 1,820 1,729 1,171 2,499 Net income 2,250 1,820 1,729 1,171 2,499 Net income attributable to common shareholders 2,269 1,623 1,719 1,160 2,495 Earnings per average common share (diluted): Income from continuing operations $2.54 $1.88 $2.00 $1.42 $3.75 Net income $2.54 $1.88 $2.00 $1.42 $3.75 Dividends per common share $1.24 $1.24 $1.46 $2.10 $2.10 Average shares of common stock outstanding—diluted 893 864 860 819 665 (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) 2015 2014 2013 2012 2011 Balance Sheet data: Current assets $15,334 $11,853 $9,562 $10,009 $5,713 Property, plant and equipment, net 57,439 52,170 47,330 45,186 32,570 Noncurrent regulatory assets 6,065 6,076 5,910 6,497 4,518 Goodwill 2,672 2,672 2,625 2,625 2,625 Other deferred debits and other assets 13,874 13,645 13,816 14,033 9,498 Total assets $95,384 $86,416 $79,243 $78,350 $54,924 Current liabilities $9,118 $8,762 $7,686 $7,734 $5,134 Long-term debt, including long-term debt to financing trusts 24,286 19,853 18,165 18,266 12,118 Noncurrent regulatory liabilities 4,201 4,550 4,388 3,981 3,627 Other deferred credits and other liabilities 30,457 29,118 26,064 26,552 19,570 Contingently redeemable noncontrolling interest 28 — — — — Preferred securities of subsidiary — — — 87 87 Noncontrolling interest 1,308 1,332 15 106 3 BGE preference stock not subject to mandatory redemption 193 193 193 193 — Shareholders’ equity 25,793 22,608 22,732 21,431 14,385 Total liabilities and shareholders’ equity $95,384 $86,416 $79,243 $78,350 $54,924 (a)Represents mezzanine equity related to contingently redeemable equity contributions made by a noncontrolling interest holder of one of Generation’s subsidiaries. See Note 18—Contingently Redeemable Noncontrolling Interest for further information. 72(a)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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) 2015 2014 2013 2012 2011 Statement of Operations data: Operating revenues $19,135 $17,393 $15,630 $14,437 $10,447 Operating income 2,275 1,176 1,677 1,113 2,875 Net income 1,340 1,019 1,060 558 1,771 Net income attributable to membership interest 1,372 835 1,070 562 1,771 (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) 2015 2014 2013 2012 2011 Balance Sheet data: Current assets $6,342 $7,311 $5,964 $6,211 $3,217 Property, plant and equipment, net 25,843 23,028 20,111 19,531 13,475 Other deferred debits and other assets 14,344 14,612 14,625 14,906 10,714 Total assets $46,529 $44,951 $40,700 $40,648 $27,406 Current liabilities $4,933 $4,459 $3,842 $3,969 $1,899 Long-term debt 8,869 7,582 7,111 7,422 3,647 Other deferred credits and other liabilities 19,757 18,859 17,005 16,592 13,152 Contingently redeemable noncontrolling interest 28 — — — — Noncontrolling interest 1,307 1,333 17 108 5 Member’s equity 11,635 12,718 12,725 12,557 8,703 Total liabilities and member’s equity $46,529 $44,951 $40,700 $40,648 $27,406 (a)Represents mezzanine equity related to contingently redeemable equity contributions made by a noncontrolling interest holder of one of Generation’s subsidiaries. See Note 18—Contingently Redeemable Noncontrolling Interest for further information. 73(a)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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) 2015 2014 2013 2012 2011 Statement of Operations data: Operating revenues $4,905 $4,564 $4,464 $5,443 $6,056 Operating income 1,017 980 954 886 982 Net income 426 408 249 379 416 December 31, (In millions) 2015 2014 2013 2012 2011 Balance Sheet data: Current assets $1,518 $1,723 $1,540 $1,692 $2,127 Property, plant and equipment, net 17,502 15,793 14,666 13,826 13,121 Goodwill 2,625 2,625 2,625 2,625 2,625 Noncurrent regulatory assets 895 852 933 666 699 Other deferred debits and other assets 3,992 4,365 4,325 3,984 3,975 Total assets $26,532 $25,358 $24,089 $22,793 $22,547 Current liabilities $2,766 $1,923 $2,032 $1,655 $2,071 Long-term debt, including long-term debt to financing trusts 6,049 5,870 5,235 5,492 5,391 Noncurrent regulatory liabilities 3,459 3,655 3,512 3,229 3,042 Other deferred credits and other liabilities 6,015 6,003 5,782 5,094 5,006 Shareholders’ equity 8,243 7,907 7,528 7,323 7,037 Total liabilities and shareholders’ equity $26,532 $25,358 $24,089 $22,793 $22,547 PECO 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) 2015 2014 2013 2012 2011 Statement of Operations data: Operating revenues $3,032 $3,094 $3,100 $3,186 $3,720 Operating income 630 572 666 623 655 Net income 378 352 395 381 389 Net income attributable to common shareholder 378 352 388 377 385 74Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 2012 2011 Balance Sheet data: Current assets $842 $645 $821 $1,054 $1,218 Property, plant and equipment, net 7,141 6,801 6,384 6,078 5,874 Noncurrent regulatory assets 1,583 1,529 1,448 1,378 1,216 Other deferred debits and other assets 801 885 868 793 814 Total assets $10,367 $9,860 $9,521 $9,303 $9,122 Current liabilities $944 $653 $889 $1,158 $1,145 Long-term debt, including long-term debt to financing trusts 2,464 2,416 2,120 1,821 1,772 Noncurrent regulatory liabilities 527 657 629 538 585 Other deferred credits and other liabilities 3,196 3,013 2,818 2,717 2,595 Preferred securities — — — 87 87 Shareholders’ equity 3,236 3,121 3,065 2,982 2,938 Total liabilities and shareholders’ equity $10,367 $9,860 $9,521 $9,303 $9,122 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) 2015 2014 2013 2012 2011 Statement of Operations data: Operating revenues $3,135 $3,165 $3,065 $2,735 $3,068 Operating income 558 439 449 132 314 Net income 288 211 210 4 136 Net income (loss) attributable to common shareholder 275 198 197 (9) 123 December 31, (In millions) 2015 2014 2013 2012 (a) 2011 (a) Balance Sheet data: Current assets $845 $951 $1,009 $979 $969 Property, plant and equipment, net 6,597 6,204 5,864 5,498 5,132 Noncurrent regulatory assets 514 510 524 522 551 Other deferred debits and other assets 339 391 442 486 531 Total assets $8,295 $8,056 $7,839 $7,485 $7,183 Current liabilities $1,134 $794 $800 $980 $675 Long-term debt, including long-term debt to financing trusts and variable interestentities 1,732 2,109 2,179 1,949 2,166 Noncurrent regulatory liabilities 184 200 204 214 201 Other deferred credits and other liabilities 2,368 2,200 2,101 1,984 1,840 Preference stock not subject to mandatory redemption 190 190 190 190 190 Shareholders’ equity 2,687 2,563 2,365 2,168 2,111 Total liabilities and shareholders’ equity $8,295 $8,056 $7,839 $7,485 $7,183 (a)BGE retrospectively reclassified certain regulatory assets and regulatory liabilities to conform to the current year presentation. 75Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. • 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 financial statements since April 1, 2014. • ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission anddistribution services in northern Illinois, including the City of Chicago. • PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of 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 Power Regions in Generation), ComEd, PECO and BGE. See Note 25—Segment Information of theCombined Notes to Consolidated Financial Statements for additional information regarding Exelon’s reportable segments. Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. 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. Financial Results. The following consolidated financial results reflect the results of Exelon for the year ended December 31, 2015 comparedto the same period in 2014. The 2014 financial results only include the operations of CENG on a fully consolidated basis from the date Generationassumed 76Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsoperational control, April 1, 2014, through December 31, 2014. All amounts presented below are before the impact of income taxes, except asnoted. The Years Ended December 31, Favorable(Unfavorable)Variance 2015 2014 Generation ComEd PECO BGE Other Exelon Exelon Operating revenues $19,135 $4,905 $3,032 $3,135 $(760) $29,447 $27,429 $2,018 Purchased power and fuel expense 10,021 1,319 1,190 1,305 (751) 13,084 13,003 (81) Revenue net of purchased power and fuel expense 9,114 3,586 1,842 1,830 (9) 16,363 14,426 1,937 Other operating expenses Operating and maintenance 5,308 1,567 794 683 (30) 8,322 8,568 246 Depreciation and amortization 1,054 707 260 366 63 2,450 2,314 (136) Taxes other than income 489 296 160 224 31 1,200 1,154 (46) Total other operating expenses 6,851 2,570 1,214 1,273 64 11,972 12,036 64 Equity in losses of unconsolidated affiliates — — — — — — (20) 20 Gain on sales of assets 12 1 2 1 2 18 437 (419) Gain on consolidation and acquisition of businesses — — — — — — 289 (289) Operating income (loss) 2,275 1,017 630 558 (71) 4,409 3,096 1,313 Other income and (deductions) Interest expense, net (365) (332) (114) (99) (123) (1,033) (1,065) 32 Other, net (60) 21 5 18 (30) (46) 455 (501) Total other income and (deductions) (425) (311) (109) (81) (153) (1,079) (610) (469) Income (loss) before income taxes 1,850 706 521 477 (224) 3,330 2,486 844 Income taxes 502 280 143 189 (41) 1,073 666 (407) Equity in (losses) earnings of unconsolidated affiliates (8) — — — 1 (7) — (7) Net income (loss) 1,340 426 378 288 (182) 2,250 1,820 430 Net income (loss) attributable to noncontrolling interests andpreference stock dividends (32) — — 13 — (19) 197 (216) Net income (loss) attributable to common shareholders $1,372 $426 $378 $275 $(182) $2,269 $1,623 $646 (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 $2,269 million for the year ended December 31, 2015 as compared to $1,623million for the year ended December 31, 2014, and diluted earnings per average common share were $2.54 for the year ended December 31, 2015as compared to $1.88 for the year ended December 31, 2014. Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $1,937 millionas compared to 2014. The year-over-year increase was primarily due to the following favorable factors: • Increase of $666 million at Generation primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015, benefit oflower cost to serve load (including the absence of higher procurement costs for replacement power in 2014), the cancellation of the DOEspent 77 (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 nuclear fuel disposal fee, increased capacity prices, the inclusion of Integrys’ results in 2015, favorability from portfolio managementoptimization activities in the Mid-Atlantic and Midwest regions, and increased load served, partially offset by lower margins resultingfrom the 2014 sales of generating assets, lower realized energy prices, and the absence of the 2014 fuel optimization opportunities inthe South region due to extreme cold weather; • Increase of $848 million at Generation due to mark-to-market gains of $257 million in 2015 from economic hedging activities ascompared to losses of $591 million in 2014; • Increase of $132 million at Generation related to amortization of contracts recorded at fair value associated with prior acquisitions; • Increase of $228 million at ComEd primarily due to increased electric distribution and transmission formula rate revenues (reflecting theimpacts of increased capital investment, partially offset by lower allowed electric distribution ROE); • Increase of $9 million at PECO primarily due to favorable weather and volume; and • Increase of $82 million at BGE primarily due to increased distribution revenue pursuant to increased rates effective December 2014 as aresult of the electric and natural gas distribution rate case order issued by the Maryland PSC and increased transmission revenue. The year-over-year increase in operating revenue net of purchased power and fuel expense was partially offset by the followingunfavorable factors: • Decrease of $38 million at ComEd due to unfavorable weather and volume. Operating and maintenance expense decreased by $246 million as compared to 2014 primarily due to the following favorable factors: • Long-lived asset impairments at Generation of $12 million in 2015 compared to $663 million in 2014. • Decrease of $44 million resulting from the absence of 2014 expenses recorded for a Constellation merger commitment at Generation; • Decreased storm costs at PECO and BGE of $78 million and $21 million, respectively; • Decreased uncollectible accounts expense at BGE of $49 million. The year-over-year decrease in operating and maintenance expense was partially offset by the following unfavorable factors: • Increase in Generation’s labor, contracting and materials costs of $323 million primarily due to the inclusion of CENG’s results on a fullyconsolidated basis in 2015 and increased contracting spend related to energy efficiency projects; • Increase of $64 million as a result of an increase in the number of nuclear refueling outage days at Generation, including Salem,primarily related to the inclusion of CENG’s plants on a fully consolidated basis in 2015; • Increase in labor, contracting and materials costs of $31 million related to preventative maintenance and other projects at ComEd; • Increased storm costs at ComEd of $27 million; • Increased costs associated with ComEd’s uncollectible accounts expense of $27 million; and • An increase in pension and non-pension postretirement benefits expense of $47 million primarily at Exelon, Generation, and ComEd,resulting from the unfavorable impact of lower assumed pension and OPEB discount rates for 2015 and an increase in the lifeexpectancy assumption for plan participants in 2015, partially offset by cost savings from plan design changes for certain OPEB planseffective April 2014 and forward. 78Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDepreciation and amortization expense increased by $136 million primarily as a result of the inclusion of CENG’s results on a fullyconsolidated basis in 2015, increased nuclear decommissioning amortization at Generation, and increased depreciation expense across theoperating companies for ongoing capital expenditures. Taxes other than income increased $46 million primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015 andincreased sales and use tax at Corporate. Gain on sales of assets decreased $419 million as a result of the absence of 2014 gains recorded on the sales of ownership interest incertain generating stations. Gain on consolidation and acquisition of businesses decreased by $289 million due to a $261 million gain upon consolidation of CENG in2014 resulting from the difference in fair value of CENG’s net assets as of April 1, 2014, and the equity method investment previously recorded onGeneration’s and Exelon’s books and the settlement of pre-existing transactions between Generation and CENG, and a $28 million bargain-purchase gain in 2014 related to the Integrys acquisition. Interest expense decreased by $32 million primarily as a result of mark-to market gains in 2015 as compared to mark-to-market losses in2014 associated with an interest rate swap terminated in June 2015, partially offset by higher debt in 2015 related to financing activities associatedwith the pending PHI merger. Other, net decreased by $501 million primarily at Generation as a result of the change in realized and unrealized gains and losses on NDTfunds. Exelon’s effective income tax rates for the years ended December 31, 2015 and 2014 were 32.2% and 26.8%, respectively. See Note 15—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, 2015 and 2014, 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, 2015 were $2,227 million, or $2.49 per diluted share,compared with adjusted (non-GAAP) operating earnings of $2,068 million, or $2.39 per diluted share, for the same period in 2014. In addition to netincome, Exelon evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believesit represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs,expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-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. 79Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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, 2015 as compared to 2014: For the years ended December 31, 2015 2014 (All amounts after tax; in millions, except per share amounts) EarningsperDilutedShare EarningsperDilutedShare Net Income Attributable to Common Shareholders $2,269 $2.54 $1,623 $1.88 Mark-to-Market Impact of Economic Hedging Activities (158) (0.18) 363 0.42 Unrealized Losses (Gains) Related to NDT Fund Investments 115 0.13 (86) (0.10) Plant Retirements and Divestitures — — (245) (0.28) Asset Retirement Obligation (6) (0.01) (13) (0.02) Merger and Integration Costs 58 0.07 124 0.14 Amortization of Commodity Contract Intangibles (5) — 64 0.07 Reassessment of State Deferred Income Taxes 41 0.05 (27) (0.03) Long-Lived Asset Impairments 21 0.02 435 0.50 Bargain-Purchase Gain on Integrys Acquisition — — (28) (0.03) Gain on CENG Integration — — (159) (0.18) Tax Settlements (52) (0.06) (106) (0.12) Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (21) (0.02) 61 0.07 PHI Merger Related Redeemable Debt Exchange 13 0.01 — — Reduction in State Income Tax Reserve (10) (0.01) — — Midwest Generation Bankruptcy Recoveries (6) (0.01) — — CENG Non-Controlling Interest (32) (0.04) 62 0.07 Adjusted (non-GAAP) Operating Earnings $2,227 $2.49 $2,068 $2.39 (a)Reflects the impact of (gains) losses for the years ended December 31, 2015 and 2014 (net of taxes of $99 million and $232 million, respectively) on Generation’s economichedging activities. See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’shedging activities.(b)Reflects the impact of unrealized losses (gains) for the years ended December 31, 2015 and 2014 (net of taxes of $148 million and $77 million, respectively) on Generation’s NDTfund investments for Non-Regulatory Agreement Units. See Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additionaldetail 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 year ended December 31, 2014 (net of taxes of $163 million,respectively).(d)Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the Non-Regulatory Agreement Units for the yearsended December 31, 2015 and 2014 (net of taxes of $4 million).(e)Reflects certain costs associated with mergers and acquisitions incurred for the years ended December 31, 2015 and 2014 (net of taxes of $38 million and $45 million,respectively) including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisitioncontingencies related to the Constellation merger, CENG integration and the Integrys and pending PHI acquisitions.(f)Reflects the non-cash impact for the years ended December 31, 2015 and 2014 (net of taxes of $3 million and $68 million, respectively) of the amortization of commodity contractsrecorded at fair value associated with prior acquisitions, if and when applicable.(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 2015, reflects charges to earnings primarily related to the impairments of investments in long-term leases and Upstream assets (net of taxes of $13 million). In 2014, reflectscharges to earnings related to the impairments of certain generating assets held for sale, investment in long-term leases, Upstream assets, and wind generating assets (net oftaxes of $250 million).(i)Reflects the excess of the fair value of assets and liabilities acquired over the purchase price of Integrys (net of taxes of $16 million). 80 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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(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 2015 and 2014 of certain income tax positions on Constellation’s pre-acquisition tax returns.(l)Reflects the impact of mark-to-market activity on forward-starting interest rate swaps held at Exelon Corporate related to financing for the pending PHI acquisition for the yearsended December 31, 2015 and 2014 (net of taxes of $14 million and $39 million, respectively).(m)Reflects the costs associated with the exchange and redemption in December 2015 of certain mandatorily redeemable debt issued to finance the PHI merger (net of taxes of $8million).(n)Reflects the reduction of a previously recorded state income tax reserve associated with the 2014 sales of Keystone and Conemaugh for the year ended December 31, 2015.(o)Reflects a benefit for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy for the year ended December 31, 2015 (netof taxes of $4 million).(p)Represents Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments andmark-to-market activity in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, costs incurred associated with the integration, non-cashamortization of intangible assets, net, related to commodity contracts, mark-to-market activity, and changes in asset retirement obligations. Merger and Acquisition Costs As presented in the table above, Exelon has incurred and will continue to incur costs associated with the Integrys and PHI acquisitionsincluding employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), financing costs, integration initiatives, andcertain pre-acquisition contingencies. For the years ended December 31, 2015 and 2014, expense has been recognized for costs incurred to achieve the Constellation merger,CENG integration, Integrys acquisition and pending PHI acquisition as follows: Pre-tax Expense Twelve Months Ended December 31, 2015 Merger Integration and Acquisition Expense: Generation ComEd PECO BGE Exelon Financing $— $— $— $— $21 Transaction — — — — 23 Other 32 9 4 5 51 Total $32 $9 $4 $5 $95 Pre-tax Expense Twelve Months Ended December 31, 2014 Merger Integration and Acquisition Expense: Generation ComEd PECO BGE Exelon Financing $— $— $— $— $31 Transaction — — — — 26 Regulatory commitments 44 — — — 44 Employee-related 5 — — — 5 Other 56 4 2 2 65 Total $105 $4 $2 $2 $171 (a)Reflects costs incurred at Exelon related to the financing of the PHI acquisition, including upfront credit facility fees. Excludes mark-to-market activity on forward-starting swaps andcosts associated with the exchange and redemption of mandatorily redeemable debt.(b)External, third party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing oftransactions.(c)Costs to integrate CENG, Constellation and Integrys processes and systems into Exelon and to terminate certain Constellation debt agreements. Also includes professional feesprimarily related to integration for the pending PHI acquisition. 81 (a) (b) (c) (a) (b) (d) (e) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)Reflects costs incurred at Generation for a Constellation merger commitment for the year ended December 31, 2014.(e)Costs primarily for employee severance, pension and OPEB expense and retention bonuses. As of December 31, 2015, Exelon projects incurring total PHI acquisition and integration related costs of approximately $700 million,excluding the amounts Exelon and PHI are committed, if approved, to provide to the PHI utility’s respective customers. Of this amount, including2014 and through December 31, 2015, Exelon has incurred approximately $300 million of costs associated with the proposed merger. Included inthis amount are costs to fund the merger of which $76 million has been expensed, $56 million has been paid and recorded as deferred debtissuance costs and $60 million has been incurred and charged to common stock. The remaining costs will be primarily within Operating andmaintenance expense within Exelon’s Consolidated Statements of Operations and Comprehensive Income and will also include approximately $60million for integration costs expected to be capitalized to Property, plant and equipment. The increase from the previous estimate of $635 million isdue to higher transaction costs primarily driven by the merger delay. This increase in transaction costs is partially offset by lower integration costs. Pursuant to the conditions set forth by the MDPSC in its approval of the Constellation merger transaction, Exelon committed to provide apackage of benefits to BGE customers, and make certain investments in the City of Baltimore and the State of Maryland, resulting in an estimateddirect investment 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 for office space that was contingent upon the developer obtaining all required approvals, permitsand financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014when these outstanding contingencies were met by the developer. Construction began late in the second quarter of 2014 and the building isexpected to be ready for occupancy by the end of 2016. See Note 23—Commitments and Contingencies of the Combined Notes to ConsolidatedFinancial Statements for further information related to the lease commitments. Exelon’s Strategy and Outlook for 2016 and Beyond Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financialdiscipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix ofattributes that, when combined, offer shareholders and customers a unique value proposition: • Exelon’s utilities provide a foundation for stable earnings, which translates to a stable currency in our stock. • Generation’s competitive businesses provide free cash flow to invest primarily into the utilities and in long-term, contracted assets. Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change. 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 improving 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. Additionally, 82Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure,and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company. 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 to reduce earnings volatility.Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer facingactivities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including 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 financial priorities are to maintain investment grade credit metrics at each of Exelon, Generation, ComEd, PECO and BGE, tomaintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity marketcycle and through stable earnings growth. Exelon’s Board of Directors approved a revised dividend policy. The approved policy would raise ourdividend 2.5% each year for the next three years, beginning with the June 2016 dividend. The Board will take formal action to declare the nextdividend in the second quarter. Various 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. Continually optimizing the cost structure is a key component of Exelon’s financial strategy. Through a recent focused cost managementprogram the company has committed to reducing operation and maintenance expenses and capital costs by $350 million, of which approximately35% of run-rate savings are expected to be achieved by the end of 2016 and fully realized in 2018. Savings will be allocated approximately 75%,14%, 6% and 6% to Generation, ComEd, PECO and BGE, respectively. Exelon anticipates the earnings per share savings impact on EPS will bewithin $0.13 to $0.18 from 2018 forward. 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. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Based onthe outstanding shares of PHI’s common stock as of December 31, 2015, PHI shareholders would receive $6.9 billion in total cash. In addition, inconnection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $180 million of a class ofnonvoting, nonconvertible and nontransferable preferred securities of PHI. The preferred securities are included in Other non-current assets onExelon’s Consolidated Balance Sheet. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrueddividends, if any. On November 2, 2015, Exelon and PHI each filed a new Notification and Report Form with the DOJ under the Hart-Scott-Rodino AntitrustImprovements Act of 1976 (HSR Act) due to the expiration of the original filing. The HSR Act waiting period expired on December 2, 2015, and theHSR Act no longer precludes completion of the merger. 83Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU), the DelawarePublic Service Commission (DPSC), the Maryland Public Service Commission (MDPSC) and the FERC have approved the merger of PHI andExelon. The Federal Communications Commission has also approved the transfer of certain PHI communications licenses. On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI,Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits to ACEcustomers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregatevalue of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million. The March 6,2015, order by the NJBPU approving the merger required that the consummation of the merger must take place no later than November 1, 2015unless otherwise extended by the Board. On October 15, 2015, the NJBPU extended the November 1, 2015 date to June 30, 2016. On February 13, 2015, Exelon and PHI announced that they had reached a settlement agreement in the proceeding before the DPSC toreview the proposed merger. The settlement, which was amended on April 7, 2015, was signed and filed by Exelon, PHI, Delmarva Power & LightCompany (DPL), the DPSC Staff, the Delaware Public Advocate, the Delaware Department of Natural Resources and Environmental Control, theDelaware Sustainable Energy Utility, the Mid-Atlantic Renewable Energy Coalition and the Clean Air Council. As part of this settlement, Exelonand PHI proposed a package of benefits to DPL customers and the state of Delaware including the establishment of customer rate credits of $40million for DPL customers in Delaware, $2 million of funding for energy efficiency programs for DPL low income customers, and $2 million offunding for workforce development. On June 2, 2015, the DPSC issued an order accepting the settlement and approving the merger betweenExelon and PHI. On March 17, 2015, Exelon and PHI announced that they had reached settlements with multiple parties in the Maryland proceeding to reviewthe proposed merger after filing a Request for Adoption of Settlements with the MDPSC. The settlements were signed and filed by Exelon, PHI,Montgomery County, Prince George’s County, the National Consumer Law Center, National Housing Trust, the Maryland Affordable HousingCoalition, the Housing Association of Nonprofit Developers, and a consortium of recreational trail advocacy organizations led by the Mid-AtlanticOff-Road Enthusiasts. Exelon and PHI also announced a settlement with The Alliance for Solar Choice. On May 15, 2015, the MDPSC approvedthe merger after modifying a number of the conditions in the settlements, resulting in total rate credits of $66 million, funding for energy efficiencyprograms of $43.2 million, a Green Sustainability Fund of $14.4 million, 20 MWs of renewable generation development and increased penaltiesrelated to reliability commitments. On May 18, 2015, Exelon and PHI accepted and committed to fulfill the conditions. On June 11, 2015, the Maryland Office of People’s Counsel (OPC), the Sierra Club, and the Chesapeake Climate Action Network filedPetitions for Judicial Review of the MDPSC’s approval of the merger with the Circuit Court for Queen Anne’s County. On June 23, 2015, PublicCitizen, Inc. filed its Petition for Judicial Review with the Circuit Court for Queen Anne’s County. On July 10, 2015, Exelon and PHI filed aresponse in opposition to the Petitions for Review. On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery andpresentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 theSierra Club and the Chesapeake Climate Action Network filed a joint motion to stay. In July and August, Exelon, PHI, the MDPSC, PrinceGeorge’s County and Montgomery County filed responses opposing the motions to stay. The judge issued an order denying the motions for stayon August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for 84Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsjudicial review filed by the OPC, the Sierra Club, the Chesapeake Climate Action Network (CCAN) and Public Citizen, Inc. On January 19, 2016,the OPC filed a notice of appeal to the Maryland Court of Special appeals, and on January 21, Sierra Club and CCAN filed a notice of appeal. Inthe ordinary course this appeal would be resolved no earlier than third quarter 2016. On August 27, 2015, the District of Columbia Public Service Commission (DCPSC) issued an Opinion and Order denying approval of themerger, concluding that the merger as presented was not in the public interest. Exelon and PHI filed an Application for Reconsideration with theDCPSC on September 28, 2015. On October 6, 2015, Exelon, PHI, the District of Columbia Government, the Office of Peoples Counsel, theDistrict of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust—Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties)entered into a Nonunanimous Full Settlement Agreement and Stipulation (Settlement Agreement) with respect to the merger. Exelon and PHIsubsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of theSettlement Agreement and granting additional requested relief. The new package of benefits totals $78 million and includes commitments toprovide relief of residential customer base rate increases of $26 million, one-time direct bill credits of $14 million, low-income energy assistance of$16 million, improved reliability, a cleaner and greener D.C. through funding energy efficiency programs and development of renewable energy, andinvestment in local jobs and the local economy through workforce development of $5 million. It also guarantees charitable contributions totaling$19 million over 10 years. On October 28, 2015, the DCPSC agreed to reopen the approval application to allow for consideration of the Settlement Agreement. Sincethen, parties supporting and opposing the Settlement filed testimony, participated in formal hearings and, on December 23, 2015, submitted finalbriefs to the DCPSC. The parties now await a formal decision from the DCPSC. The Merger Agreement provides that either Exelon or PHI mayterminate the Merger Agreement if the merger is not completed by October 28, 2015. Pursuant to a Letter Agreement related to the SettlementAgreement, Exelon and PHI have agreed, among other things, that they will not exercise their rights to terminate the Merger Agreement beforeMarch 4, 2016, except under limited circumstances. If the DCPSC does not approve the Settlement Agreement by March 4, 2016, either Exelon orPHI may terminate the Settlement Agreement. The settlements reached and commission orders received to date in Delaware, Maryland and New Jersey include a “most favored nation”provision which, generally speaking, requires allocation of merger benefits proportionately across all the jurisdictions. When applying the mostfavored nation provision to the settlement terms and other conditions established in the merger approvals received to date, and as proposed in theSettlement Agreement filed with the DCPSC, Exelon and PHI currently estimate direct benefits of $430 million or more on a net present valuebasis (excluding charitable contributions and renewable generation commitments) will be provided, including rate credits, funding for energyefficiency programs and other required commitments. Exelon and PHI anticipate substantially all of such amounts will be charged to earnings atthe time of merger close and will be paid by the end of 2017. An additional $53 million will be charged to earnings for charitable contributions,which are required to be paid over a period of 10 years. Commitments to develop renewable generation, which are expected to be primarily capitalin nature, will be recognized as incurred. Upon completion of the merger, the actual nature, amount, timing and financial reporting treatment forthese commitments may be materially different from the current projection. 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. Exelon wasalso named in a federal court suit making similar claims. In September 2014, the parties reached a proposed settlement that would resolve allclaims, which is 85Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentssubject to court approval. Final court approval of the proposed settlement is not anticipated until approximately 90 days after merger close. Exelondoes not believe these suits will impact the completion of the transaction, and they are not expected to have a material impact on Exelon’s resultsof operations. Including 2014 and through December 31, 2015, Exelon has incurred approximately $259 million of expense associated with the proposedmerger. Of the total costs incurred, $121 million is primarily related to acquisition and integration costs and $138 million are for costs incurred tofinance the transaction. The financing costs include $22 million of costs associated with the private exchange offer and redemption of certainSenior Unsecured Notes (see Note 14—Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for furtherinformation on the exchange), as well as, a net loss of $64 million related to the settlement of forward-starting interest-rate swaps. These swapswere terminated in connection with the $4.2 billion issuance of debt; refer to Note 13—Derivative Financial Instruments of the Combined Notes tothe Consolidated Financial Statements for more information. The financing costs exclude costs to issue equity and the initial debt offering whichwe recorded to Exelon’s Consolidated Balance Sheets. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259million to $293 million plus certain expenses. If the Merger Agreement is terminated due to a failure to obtain a required regulatory approval,Exelon may be required to pay PHI a termination fee equal to $180 million through the redemption by PHI of the outstanding nonvoting preferredsecurities described above for no consideration other than the nominal par value of the stock, plus reimbursement of PHI’s documented out-of-pocket expenses up to a maximum of $40 million. Merger Financing Exelon has raised cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments, through theissuance of $4.2 billion of debt (of which $3.3 billion remains after execution of the exchange offer, see Note 14—Debt and Credit Agreements forfurther information on the exchange), $1.15 billion of junior subordinated notes in the form of 23 million equity units, the issuance of $1.9 billion ofcommon stock, cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion) and theremaining balance from cash on hand and/or short-term borrowings available to Exelon. Exelon will have sufficient cash to fund the all-cashpurchase price, acquisition and integration related costs, and merger commitments. See Note 14—Debt and Credit Agreements and Note 19—Shareholder’s Equity of the Combined Notes to the Consolidated Financial Statements for further information on the debt and equity issuances. Exelon has listed various potential risks relating to the pending merger with PHI (see ITEM 1A. RISK FACTORS), including difficulties thatmay be encountered in satisfying the conditions to completion of the merger and the potential for developments that might have an adverse effecton Exelon 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. Refer to Note 4—Mergers, Acquisitions, and Dispositions ofthe Combined Notes to Consolidated Financial Statements for additional information on the merger transaction. Implications of Potential Early Plant Retirements Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors thatwill continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacityauctions, potential legislative solutions in New York and Illinois such as the proposed Low Carbon Portfolio Standard (LCPS) legislation, the impactof final rules from the EPA requiring reduction of carbon and other emissions and the efforts of the states to implement those final rules, and theoutcome of the Ginna RSSA hearing and settlement procedures and the resulting contractual terms and conditions. 86Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 September 10, 2015, after considering the results of the recent PJM capacity auctions, Exelon and Generation decided to defer decisionsabout the future operations of its Quad Cities and Byron nuclear plants and will offer both plants in the 2019/2020 auction in May 2016. As a resultof clearing the other PJM capacity auction in September 2015 for the 2017/2018 transitional capacity auction, Exelon and Generation will continueto operate its Quad Cities nuclear power plant through at least May 2018. The Byron plant is already obligated to operate through May 2019. OnOctober 29, 2015, Exelon and Generation announced the deferral of any decision about the future operations of its Clinton nuclear plant and plansto bid the plant into the MISO capacity auction for the 2016-2017 planning year April 2016. This decision was driven by MISO’s acknowledgmentof the need for market design changes to ensure long-term power system reliability in southern Illinois, the desire to provide Illinois policy makerswith additional time to consider needed reforms as well as the potential long-term impact of EPA’s Clean Power Plan. Exelon and Generationpreviously committed to cease operation of the Oyster Creek nuclear plant by the end of 2019. Exelon and Generation have not made anydecisions regarding potential nuclear plant closures at other sites at this time. As a result of a decision to early retire one or more other nuclear plants, certain changes in accounting treatment would be triggered andExelon’s and Generation’s results of operations and cash flows could be materially affected by a number of items including, among other items:accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flightcapital projects, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, relocation, retention, etc.),accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioningtrust funds. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expendituresin the periods beyond shutdown. While there are a number of Generation’s nuclear plants that are at risk of early retirement, the following tableprovides the balance sheet amounts as of December 31, 2015 for significant assets and liabilities associated with the three nuclear plantscurrently considered by management to be at the greatest risk of early retirement due to their current economic valuations and other factors: (in millions) Quad Cities Clinton Ginna Total Asset Balances Materials and supplies inventory $50 $57 $29 $136 Nuclear fuel inventory, net 218 107 60 385 Completed plant, net 1,030 579 127 1,736 Construction work in progress 11 9 11 31 Liability Balances Asset retirement obligation (698) (401) (644) (1,743) NRC License Renewal Term 2032 2046 2029 (a)Assumes Clinton seeks and receives a 20-year operating license renewal extension. In the event a decision is made to retire early one or more nuclear plants, the precise timing of the retirement date, and resulting financialstatement impact, is uncertain and would be influenced by a number of factors such as the results of any transmission system reliability studyassessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors.However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity obligations and just priorto its next scheduled nuclear refueling outage date in that year. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will beavailable in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon the assumption thatdecommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC 87(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsminimum funding test, then Generation would be required to take steps, such as providing financial guarantees through letters of credit or parentcompany guarantees or making additional cash contributions to the NDTF to ensure sufficient funds are available. As of December 31, 2015, all three of Generation’s plants at the highest risk of early retirement (Quad Cities, Clinton, and Ginna) pass theNRC minimum funding test based on their current license lives. See Note 16—Asset Retirement Obligations for additional information on NRCminimum funding requirements. However, in the event of an early retirement just before their next individual refueling outages, it is estimated thatClinton and Ginna would no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activitiesand a shorter time period over which the NDTF investments could appreciate in value. Quad Cities would also be at risk. However, the size of theguarantees are ultimately dependent on the decommissioning approach adopted at each site (i.e., DECON, Delayed DECON and SAFSTOR), theassociated level of costs, and the decommissioning trust fund investment performance going forward. Considering the three alternativedecommissioning approaches available to Generation for each site, parental guarantees of up to $315 million, $260 million, and $65 million forClinton, Ginna, and Quad Cities, respectively, could be required in order for each site to access its NDTF for radiological decommissioning costs. In addition, upon issuance of any required financial guarantees, while all three sites would be able to utilize their respective decommissioningtrust funds for radiological decommissioning costs, the NRC must approve an additional exemption in order for Generation to utilize the NDTFfunds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs). If a unit does not receive thisexemption, the costs would be borne by Generation. Accordingly, based on current projections, it is expected that some portion of the spent fuelmanagement and/or site restoration costs would need to be funded through supplemental cash from Generation. While the ultimate amounts mayvary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under DOE reimbursementagreements or future litigation, across the three alternative decommissioning approaches available to Generation, for the next 10 years, Clintonand Ginna could incur spent fuel management and site restoration costs of up to $165 million and $115 million, net of taxes, respectively. Thecosts associated with Ginna would be shared by the plant co-owners at their respective ownership percentages. If Quad Cities fails the exemptiontest, at its ownership percentage Generation could be required to pay for spent fuel management costs of up to $180 million, net of taxes, butQuad Cities is better positioned to pass the test than the other two plants. 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. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacitymarket construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliabilitylargely by limiting the excuses for non-performance and by increasing the penalties for performance failures. The proposal permits suppliers toinclude in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected toput upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve 88Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsreliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments tosuppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participatedin the FERC proceeding including filing comments. On June 9, 2015, FERC approved PJM’s filing largely as proposed by PJM, includingtransitional auction rules for delivery years 2016/2017 through 2017/2018. As a result of this and several related orders, PJM hosted its 2018/2019Base Residual Auction (results posted on August 21, 2015) and its transitional auction for delivery year 2016/2017 (results posted on August 31,2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). MISO Capacity Market Results. On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of itscapacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region indownstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that wasin effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation’s ratable hedgingstrategy, the results of the capacity auction have not had a material impact on Exelon’s and Generation’s consolidated results of operations andcash flows. Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest ElectricCooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just andreasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should beestablished and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated. On October 1, 2015, the FERC announced that it was conducting a non-public investigation (that does not involve Exelon or Generation) intowhether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, the FERC issued a decision thatcertain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. TheFERC ordered that certain rules must be changed for the next auction scheduled for April 2016 that will set capacity prices beginning June 1,2016. In response to this order, MISO must file certain rule changes with the FERC within 30 days and certain other changes within 90 days. TheFERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refundsare appropriate. The FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would becalculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings.Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to thepotential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation’s future results of operations andcash flows. See Note 9—Implications of Potential Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements foradditional information on the impacts of the MISO announcement. MISO has acknowledged the need for capacity market design changes in the zone 4 region and stated that reforms to its capacity marketprocess may be required to drive future investment and that it plans to engage stakeholders to consider such reforms. The FERC has alsoencouraged such efforts. 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. 89Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 into 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 would be in commercial operation by June 1, 2015. CPVsubsequently sought to extend that date. The CfD mandated that utilities (including BGE) pay (or receive) the difference between CPV’s contractprice and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market. Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The actions taken by theMDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey andMaryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Each of those decisionswas upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. However, the U.S.Supreme Court has agreed to review the matter, and there is risk the Supreme Court will overrule the lower courts. As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offeredand cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respectivecontracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to doso in future auctions to the detriment of Exelon’s market driven position. While the court decisions in New Jersey and Maryland are positivedevelopments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacityauctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs,which could substantially impact Exelon’s market driven position and could have a significant effect on Exelon’s financial results of operations,financial position and cash flows. One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) have initiated actions at thePublic Utilities Commission of Ohio (PUCO) to obtain approval for Riders that would effectively allow these two companies to pass through to allcustomers in their service territories the differences between their costs and market revenues on PPAs entered into between the utility and itsmerchant generation affiliate. Collectively more than 6,000MW of primarily coal-fired generation owned by FE and AEP’s affiliates seek ratepayerguaranteed subsidies via the proposed Riders. Thus, the Riders are similar to the CfDs described above (except that the PPA Riders in Ohio wouldapply to certain existing generation facilities whereas the CfDs applied to new generation facilities). While AEP and FE initially filed for theseRiders in 2013 and 2014, respectively, it was not until late 2015 that the proposals obtained meaningful traction when PUCO staff entered into asettlement and stipulation with the Ohio utilities supporting the proposals and recommending that the PUCO approve the Riders. Exelon is aparticipant in these proceedings. Although the matter is still in hearing and a decision by the PUCO is not expected until late February/early March2016, it is increasingly likely that these subsidies may be approved by the PUCO. Litigation around these approvals is also likely. Exelon opposes the proposals in Ohio, continues to monitor developments in Maryland and New Jersey, and participates in stakeholder andother processes to ensure that similar state subsidies are 90Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 developed. Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers tosubsidize or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, orthat would threaten the reliability and value of the integrated electricity grid. Energy Demand. Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity forBGE and PECO; and a decrease in projected load for electricity for ComEd. BGE, PECO and ComEd are projecting load volumes to increase(decrease) by 1.5%, 0.4% and (0.3)%, respectively, in 2016 compared 2015. 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 serve. The market experienced high price volatility in the first quarter of 2014 whichcontributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected toremain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (includingGeneration) will continue to use their retail operations to hedge generation output. Strategic Policy Alignment Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance 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 first, second, third and fourth quarter 2015 and first quarter 2016 dividends of $0.31 per share each onExelon’s common stock. The dividends for the first, second, third and fourth quarter 2015 were paid on March 10, 2015, June 10,2015, September 10, 2015 and December 10, 2015. The first quarter 2016 dividend is payable on March 10, 2016. All future quarterly dividends require approval by Exelon’s board of directors. Exelon’s Board of Directors approved a revised dividend policy.The approved policy would raise our dividend 2.5% each year for the next three years, beginning with the June 2016 dividend. The Board will takeformal action to declare the next dividend in the second quarter. 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 2015 and 2016. However, Generation is exposed to relatively greater commodity price risk in the subsequent years withrespect to which a larger portion of its electricity portfolio is currently unhedged. As of December 31, 2015, the percentage of expected generationhedged for the major reportable segments was 90%-93%, 60%-63% and 28%-31% for 2016, 2017, and 2018 respectively. The percentage ofexpected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energythat best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model thatmakes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, 91Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsload following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options andswaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years aswell. 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, or acombination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal,oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurementcontracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at thecontracted prices. Approximately 50% of Generation’s uranium concentrate requirements from 2016 through 2020 are supplied by three producers.In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, althoughat prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterpartiescould have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position. ComEd, PECO and BGE mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs fromretail customers. Growth Opportunities Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’sexpertise in those areas and offering sustainable returns. Regulated Energy Businesses The proposed merger with PHI provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earningsaccretion, and dividend support. Additionally, ComEd, PECO and BGE anticipate investing approximately $18 billion over the next five years inelectric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening,advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $8billion by the end of 2020. ComEd, PECO and BGE invest in rate base where beneficial to customers and the community by increasing reliabilityand the service experience or otherwise meeting customer needs. These investments are made prudently and at the lowest reasonable cost tocustomers. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meterand Smart Grid Initiatives and infrastructure development and enhancement programs. Competitive Energy Businesses Generation continually assesses the optimal structure and composition of our generation assets as well as explores wholesale and retailopportunities within the power and gas sectors. Generation’s long-term growth strategy is to prioritize investments in long-term contractedgeneration across multiple technologies and identify and capitalize on opportunities that provide generation to load matching as a means to providestable earnings, while identifying emerging technologies where strategic investments provide the option for significant future growth or influence inmarket development. As of December 31, 2015, Generation has currently approved plans to invest a total of approximately $2 billion in 2016through 2018 on capital growth projects (primarily new plant construction and distributed generation). 92Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsLiquidity 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 $0.4 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, 2015, approximately 25%, or $2.1 billion, of the Registrants’ aggregate total commitments were with European banks. The creditfacilities include $8.4 billion in aggregate total commitments of which $6.9 billion was available as of December 31, 2015, due to outstandingletters of credit. There were no borrowings under the Registrants’ credit facilities as of December 31, 2015. See Note 14—Debt and CreditAgreements of the Combined Notes to the Consolidated Financial Statements for additional information on the credit facilities. Tax Matters See Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Environmental Legislative and Regulatory Developments. Exelon is actively involved in the EPA’s development and implementation of environmental regulations for the electric industry, in pursuit ofits business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, waterand waste controls for electric generating units, as set forth in the discussion below. These regulations have a disproportionate adverse impact onfossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in theretirement of older, marginal facilities. Retirements of coal-fired power plants will continue as additional EPA regulations take effect, and as airquality standards are updated and further restrict emissions. Due to its low emission generation portfolio, Generation will not be significantlydirectly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuelplants. Various bills have been introduced in the U.S. Congress that would prohibit or impede the EPA’s rulemaking efforts, and it is uncertainwhether any of these bills will become law. Air Quality. In recent years, the EPA has been implementing a series of increasingly stringent regulations under the Clean Air Act applicableto electric generating units. These regulations have resulted in more stringent emissions limits on fossil-fuel electric generating stations as statesimplement their compliance plans. National Ambient Air Quality Standards (NAAQS). The EPA continues to review and update its NAAQS for conventional air pollutantsrelating to ground-level ozone and emissions of particulate 93Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsmatter, SO2 and NOx. Following five years of litigation, the EPA is finalizing the Cross State Air Pollution Rule that 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. Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic airpollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-firedelectric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollutioncontrol equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however,facilities may have been granted an additional one or two year extension in limited cases. Numerous entities challenged MATS in the D.C. CircuitCourt, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. Onappeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriateand necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, itwas remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. As such, theMATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor insupport of the rule. Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHGemissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. Inthe absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, therehave been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on ClimateChange (“UNFCCC” of “Convention”). See ITEM 1.—BUSINESS,“Global Climate Change” for further discussion. 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. All ofGeneration’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculatingsystems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. Those facilities are Calvert Cliffs, Clinton,Dresden, Eddystone, Fairless Hills, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom,Quad Cities, Riverside, Salem and Schuylkill. See ITEM 1.—BUSINESS ,“Water Quality” for further discussion. Solid and Hazardous Waste. In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from powerplants became effective. The rule classifies CCR as non-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated bymost states subject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation forits owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does nothave sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted underthe new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whetherand to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites underthe new regulations. 94Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 23—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 (Exelon and Generation). In July 2011, an NRC Task Force formed inthe aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the FukushimaDaiichi Nuclear Power Station, issued a report of its review of the accident, including tiered recommendations for future regulatory action by theNRC to be taken in the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely anddo 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. Generationhas assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under reviewby the NRC staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and informationrequests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance for Generation, net ofexpected co-owner reimbursements, for the period from 2016 through 2019 is expected to be between approximately $175 million and $200 millionof capital (which includes approximately $25 million for the CENG plants) and $25 million of operating expense (which includes approximately $5million for the CENG plants). 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 and Tier 3 will impact their future financial position, results of operations, and cash flows.Generation will continue to engage in nuclear industry assessments and actions and stakeholder input. See ITEM 1A. RISK FACTORS foradditional information. Financial Reform Legislation (Exelon, Generation, ComEd, PECO, and BGE). The Dodd-Frank Wall Street Reform and ConsumerProtection Act (the Act) was enacted in July 2010. The part of the Act that applies to Exelon is Title VII, which is known as the Dodd-Frank WallStreet Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires the creation of a new regulatory regime for over-the-counter swaps(Swaps), including mandatory clearing for certain categories of Swaps, incentives to shift Swap activity to exchange trading, margin and capitalrequirements, and other obligations designed to promote transparency. For non security-based Swaps including commodity Swaps, Dodd-Frankempowers the Commodity Futures Trading Commission (CFTC) to promulgate regulations implementing the law’s objectives. The primary aim ofDodd-Frank is to regulate the key intermediaries in the Swaps market, which entities are either swap dealers (SDs), major swap participants(MSPs), and certain other financial entities, but the law also applies to a lesser degree to end-users of Swaps. On January 12, 2015, PresidentObama signed into law a bill that exempts from margin requirements Swaps used by end-users to hedge or mitigate commercial risk. Moreover,the CFTC’s Dodd-Frank regulations preserve the ability of end users in the energy industry to hedge their risks using Swaps without being subjectto mandatory clearing, and excepts or exempts end-users from many of the other substantive regulations. Accordingly, as an end-user, Generationis conducting its commercial business in a manner that does not require registration with the CFTC as an SD or MSP. Generation does notanticipate transacting in the future in a manner in which it would become a SD or MSP. There are, however, some rules, including the capital and margin rules for (non-cleared) Swaps that do not impact Generation’s collateralrequirements directly, but may have an indirect impact. 95Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsThese rules, in addition to certain international regulatory requirements still under development and that are similar to Dodd-Frank, could subjectGeneration’s SD or MSP counterparties to additional and potentially significant capitalization requirements and could motivate the SDs and MSPsto increase collateral requirements or cash postings from their counterparties, including Generation. Generation cannot predict to what extent, if any, further refinements to Dodd-Frank and international regulatory requirements relating toSwaps 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. 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 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 onAugust 5, 2014. On December 23, 2014, Generation filed its updated market power analysis for the Southeast Region which the FERC acceptedon July 16, 2015. On December 23, 2014, Generation filed its updated market power analysis for the Central Region which the FERC accepted onNovember 25, 2015. On December 29, 2015, Generation filed its updated market power analysis for the SPP Region, and the FERC has not yetacted on the filing. Illinois Low Carbon Portfolio Standard (Exelon, Generation and ComEd). In March 2015, the Low Carbon Portfolio Standard (LCPS)was introduced in the Illinois General Assembly. The legislation would require ComEd and Ameren to purchase low carbon energy credits to match70 percent of the electricity used on the distribution system. The LCPS is a technology-neutral solution, so all generators of zero or low carbonenergy would be able to compete in the procurement process, including wind, solar, hydro, clean coal and nuclear. Costs associated withpurchasing the low carbon energy credits would be collected from customers. The LCPS proposal includes consumer protection such as a pricecap that would limit the impact to a 2.015% increase based off 2009 monthly bills, or about $2 per month for the average residential electricitycustomer. The legislation also includes a separate customer rebate provision that would provide a direct bill credit to customers in the eventwholesale prices exceed a specified level. The proposed legislation is pending and Exelon and Generation continue to work with stakeholders. Legislation to Maximize Smart Grid Investments and to Promote a Cleaner and Greener Illinois (Exelon and ComEd). In March 2015,legislation was introduced in the Illinois General Assembly that would (1) build on ComEd’s investment in the Smart Grid to reinforce the resiliencyand security of the electrical grid to withstand unexpected challenges, (2) expand energy efficiency 96Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsprograms to reduce energy waste and increase customer savings, (3) further integrate clean renewable energy onto the power system, and(4) introduce a new demand-based rate design for residential customers that would allow for a more equitable sharing of smart grid costs amongcustomers. The legislation also provides for additional funding for customer assistance programs for low-income customers. The proposedlegislation is pending and ComEd continues to work with stakeholders. Distribution Formula Rate Update Filing (Exelon and ComEd). On April 15, 2015, ComEd filed its annual distribution formula rate torequest a total decrease to the revenue requirement of $50 million. On December 9, 2015, the ICC issued its final order which decreased therevenue requirement by $67 million, reflecting an increase of $85 million for the initial revenue requirement for 2015 and a decrease of $152 millionrelated to the annual reconciliation for 2014. The rates took effect in January 2016. Intervenors requested a rehearing on specific issues. See Note3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information related to distribution formula updates. 2015 Pennsylvania Electric Distribution Rate Case (Exelon and PECO). On March 27, 2015, PECO filed a petition with the PAPUCrequesting an increase of $190 million to its annual service revenues for electric delivery, which requested an ROE of 10.95%. On September 10,2015, PECO and interested parties filed with the PAPUC a petition for joint settlement for an increase of $127 million in annual distribution servicerevenue. No overall ROE was specified in the settlement. On December 17, 2015, the PAPUC approved the settlement of PECO’s electricdistribution rate case. The approved electric delivery rates became effective on January 1, 2016. The settlement includes approval of the In-Program Arrearage Forgiveness (“IPAF”) Program, which provides for forgiveness of a portion ofthe eligible arrearage balance of its low-income Customer Assistance Program (CAP) accounts receivable that will be determined as of programinception in October 2016. The forgiveness will be granted to the extent CAP customers remain current with payments. The Settlement guaranteesPECO’s recovery of two-thirds of the arrearage balance through a combination of customer payments and rate recovery, including through futurerates cases if necessary. The remaining one-third of the arrearage balance will be absorbed by PECO, of which a portion has already beenexpensed as bad debt for CAP customer’s accounts receivable balances. Although the actual arrearage balance is not defined until program inception, PECO believes that it can reasonably estimate certain CAPcustomer accounts receivable balances as of December 31, 2015 that will remain outstanding at program inception. Management determined itsbest estimate based on historical collectability information. As a result, a regulatory asset of $7 million, representing the previously incurred baddebt expense associated with the estimated eligible accounts receivable balances, was recorded on Exelon’s and PECO’s Consolidated BalanceSheets as of December 31, 2015. This estimate will be revisited on a quarterly basis through program inception. PECO Gas Main Extension Program (Exelon and PECO). On November 6, 2014, PECO filed a plan with the PAPUC requesting approvalof three initiatives to provide more incentives to customers interested in switching to natural gas service. On October 1, 2015, the PAPUCapproved the PECO Gas Main Extension Program, without modification. This approval allows local customers to pay significantly less initially tohave natural gas installed at their homes and businesses. 2015 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On November 6, 2015, and as amended on January 5, 2016,BGE filed for electric and gas base rate increases with the MDPSC, ultimately requesting an increase of $121 million and $79 million, respectively,of which $103 million and $37 million, respectively, is related to recovery of smart grid initiative costs. BGE requested a ROE for the electric andgas distribution rate case of 10.6% and 10.5%, respectively. The new 97Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 and gas base rates are expected to take effect in June 2016. BGE is also proposing to recover an annual increase of approximately $30million for Baltimore City conduit lease fees through a surcharge. BGE cannot predict how much of the requested increase the MDPSC willapprove or if it will approve BGE’s request for a conduit fee surcharge. Transmission Formula Rate Update Filing (Exelon, ComEd and BGE). On April 15, 2015 (and revised on May 19), ComEd filed itsannual 2015 transmission formula rate update with the FERC, reflecting an increased revenue requirement of $86 million, including an increase of$68 million for the initial revenue requirement and an increase of $18 million related to the annual reconciliation. The filing establishes the revenuerequirement used to set rates that took effect in June 2015, subject to review by the FERC and other parties. The time period for any challenges toComEd’s annual update expired in October 2015. No challenges were submitted. See Note 3—Regulatory Matters of the Combined Notes toConsolidated Financial Statements for further information related to transmission formula update. In April 2015, BGE filed its annual transmission formula rate update with the FERC, reflecting an increased revenue requirement of $10million, including an increase of $13 million for the initial revenue requirement, inclusive of dedicated facilities charge revenues, and a decrease of$3 million related to the annual reconciliation for 2014. The filing establishes the revenue requirement used to set rates that took effect in June2015. The time period for any challenges to BGE’s annual update expired in October 2015. No challenges were submitted. See Note 3—RegulatoryMatters of the Combined Notes to Consolidated Financial Statements for further information related to the transmission formula update. Grand Prairie Gateway Transmission Line (Exelon and ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’sapproval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. OnMay 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded toconstruction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned forreasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. The costs incurred for the project prior to May 21, 2014 wereimmaterial. ComEd has acquired numerous easements across the project route through voluntary transactions. ComEd will seek to acquire theproperty rights on the remaining 28 parcels through condemnation proceedings in the circuit courts. ComEd began construction of the line duringthe second quarter of 2015 with an in-service date expected in the second quarter of 2017. FERC Ameren Order (Exelon and ComEd). In July 2012, FERC issued an order to Ameren Corporation (Ameren) finding that Ameren hadimproperly included acquisition premiums/goodwill in its transmission formula rate, particularly in its capital structure and in the application ofAFUDC. FERC also directed Ameren to make refunds for the implied increase in rates in prior years. Ameren filed for rehearing of the July 2012order, which was denied in June 2014. On July 20, 2015, FERC approved a settlement between Ameren and its customers to resolve the matter.ComEd believes that the FERC settlement authorizing its transmission formula rate is distinguishable from the circumstances that led to the July2012 FERC order in the Ameren case. However, if ComEd were required to exclude acquisition premiums/goodwill from its transmission formularate, the impact could be material to ComEd’s results of operations and cash flows. FERC Order No. 1000 Compliance (ComEd, PECO and BGE). In FERC Order No. 1000, the FERC required public utility transmissionproviders to enhance their transmission planning procedures and their cost allocation methods applicable to certain new regional and interregionaltransmission 98Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsprojects. As part of the changes to the transmission planning procedures, the FERC required removal from all FERC-approved tariffs andagreements of a right of first refusal to build certain new transmission facilities. On October 25, 2012, certain of the PJM transmission owners,including ComEd, PECO and BGE (collectively, the PJM Transmission Owners), submitted a filing asserting that their contractual rights embodiedin the PJM governing documents continue to justify their right of first refusal to construct new reliability (and related) transmission projects and thatthe FERC should not be allowed to override such rights absent a showing that it is in the public interest to do so under the FERC’s “Mobile-Sierra”standard of review. This is a heightened standard of review which the PJM Transmission Owners argued could not be satisfied based on the factsapplicable to them. On March 22, 2013, FERC issued an order that, among other things, rejected the arguments of the PJM Transmission Ownersthat changes to the PJM governing documents were entitled to review under the Mobile-Sierra standard. The FERC’s March 22, 2013 order couldenable third parties to seek to build certain regional transmission projects that had previously been reserved for the PJM Transmission Owners,potentially reducing ComEd PECO and BGE’s financial return on new investments in energy transmission facilities. Numerous parties sought rehearing of the FERC’s March 22, 2013 order, including the PJM Transmission Owners. On May 15, 2014, FERCdenied the PJM Transmission Owners rehearing request. Several parties filed an appeal of the FERC’s May 15, 2014, Order which upheld PJM’sright of first refusal language in the D.C. Circuit. The ultimate outcome of this proceeding cannot be predicted at this time, however, it could bematerial to Exelon, ComEd, PECO and BGE’s results of operations and cash flows. 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 PHI 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 (and certain additional incentive basis points on certain projects). Theparties sought a reduction in the base return on equity to 8.7% and changes to the formula rate process. Under FERC rules, any revenues subjectto refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date ofthe 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. 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 created 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. On February 20, 2015, the Chief Judge issued an order consolidating the two complaint proceedings andestablished an Initial Decision issuance deadline of February 29, 2016. On November 6, 2015, BGE and the PHI companies and the complainants filed a settlement with FERC covering the issues raised in thecomplaints. The settlement provides for a 10% base ROE, effective March 8, 2016, which will be augmented by the PJM incentive adder of 50basis points, and refunds to BGE customers of $13.7 million. The settlement also provides a moratorium on any change in the ROE until June 1,2018. On December 16, 2015, the Presiding Administrative Law Judge submitted a Certification of the Uncontested Settlement to the FERCCommissioners. The settlement remains subject to FERC approval. See Note 3—Regulatory Matters of the Combined Notes to ConsolidatedFinancial Statements for additional information. 99Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation intended toaccelerate gas infrastructure replacements in Maryland was signed into law. The law established a mechanism, separate from base rateproceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects incurred afterJune 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject to a cap and requirean annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in asubsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates.Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued adecision conditionally approving the first five years of BGE’s plan and surcharge. On November 16, 2015, BGE filed a surcharge update to beeffective January 1, 2016, including a true-up of cost estimates included in the 2015 surcharge, along with its 2016 project list and projectedcapital estimates of $113 million to be included in the 2016 surcharge calculation. The MDPSC subsequently approved BGE’s 2016 project list andthe proposed surcharge for 2016, which included the 2015 surcharge true-up. As of December 31, 2015, BGE recorded a regulatory asset of lessthan $1 million, representing the difference between the surcharge revenues and program costs. In 2014, the residential consumer advocate in Maryland appealed MDPSC’s decision on BGE’s infrastructure replacement plan andassociated surcharge with the Baltimore City Circuit Court, who affirmed the MDPSC’s decision. On October 10, 2014, the residential consumeradvocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court. During thethird quarter of 2015, the residential consumer advocate, MDPSC, and BGE filed briefs. Oral argument in this matter was held before the Court ofSpecial Appeals on November 3, 2015. On January 28, 2016, the Maryland Court of Special Appeals issued a decision affirming the MDPSC’sdecision. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 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. 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. 100Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsNuclear Decommissioning Asset Retirement Obligations (Exelon and Generation) Generation’s ARO associated with decommissioning its nuclear units was $8.2 billion at December 31, 2015. 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 multipledecommissioning outcome scenarios. As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining moreinformation about costs associated with decommissioning activities. At the same time, regulators are gaining more information aboutdecommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants areretired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs.These factors could result in material changes to Generation’s current estimates as more information becomes available and could change thetiming and probability assigned to the decommissioning outcome scenarios. The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions forthe expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon themethodologies 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,unless circumstances warrant more frequent updates (such as a change in assumed operating life for a nuclear plant). As part of the annual coststudy update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the costestimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of thenormal five-year rotating cost study update cycle. 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. All of the nuclear AROs are adjusted each year for the updated cost escalation factors. Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenariosfor decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned tocost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base costscenario. Probabilities are also assigned to three different decommissioning approaches as follows: 1.DECON—a method of decommissioning shortly after the cessation of operation in which the equipment, structures, and portions of afacility and site containing radioactive contaminants are removed and safely buried in a LLRW landfill or decontaminated to a level thatpermits property to be released for unrestricted use, 2.Delayed DECON—similar to the DECON scenario but with a delay to allow for spent fuel to be removed from the site prior to onset ofdecommissioning activities, or 101Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 3.SAFSTOR—a method of decommissioning in which the nuclear facility is placed and maintained in such condition that the nuclearfacility can be safely stored and subsequently decontaminated to levels that permit release for unrestricted use generally within 60years after cessation of operations. The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdownand may be influenced by multiple factors including the funding status of the nuclear decommissioning trust fund at the time of shutdown. The assumed plant shutdown timing scenarios have historically included the following two alternatives: (1) the probability of operatingthrough the original 40-year nuclear license term, and (2) the probability of operating through an extended 60-year nuclear license term (regardlessof whether such 20-year license extension had been received for each unit). During 2015, due to changing market conditions and regulatoryenvironments, Generation began to consider and incorporate assumptions regarding plant shutdown timing scenarios for certain plants other thanjust the two scenarios historically considered. In addition to potential early shutdown scenarios, Generation also began in 2015 to incorporate intoits ARO estimates some probability of a second, 20-year license renewal for some nuclear units. The successful operation of nuclear plants in theU.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for potential plant operationsfor an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation evaluates and incorporates,as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates. Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generationcurrently assumes DOE will begin accepting SNF in 2025. The SNF acceptance date assumption was based on management’s estimates of theamount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For more informationregarding the estimated date that DOE will begin accepting SNF, see Note 23—Commitments and Contingencies of the Combined Notes toConsolidated Financial Statements. License Renewals. Generation has received, has applied for, or plans to seek, 20-year license renewals for all of its nuclear units.Generation has successfully secured 20-year operating license renewal extensions (i.e., extending the total license term to 60 years) for twenty-one of its nuclear units (including the two Salem units co-owned by Generation, but operated by PSEG and Braidwood Units 1 and 2 for which theNRC approved the renewed license on January 27, 2016). None of Generation’s previous applications for an operating license extension has beendenied. The 20-year license renewal for Oyster Creek nuclear unit was obtained in 2009, however, operations will cease by the end of 2019. For itsremaining three operating units, Generation is in various stages of the process of pursuing similar extensions and has filed license renewalapplications for two operating nuclear units and has until 2021 to seek license renewal for one remaining operating nuclear unit. Generation’sassumptions regarding successful license extension for the remaining three operating units for ARO determination purposes is based in part on thegood current physical condition and high performance of these nuclear units, the favorable status of the ongoing license renewal proceedings withthe NRC, and the successful renewals for twenty-one units to date. Generation estimates that the failure to obtain initial license renewals to extend the operating life from 40 years to 60 years at any of itsremaining nuclear units (assuming all other assumptions remain constant) would increase its ARO on average approximately $300 million per unitas of December 31, 2015. The size of the increase to the ARO for a particular nuclear unit is dependent upon the current stage in its originallicense term and its specific decommissioning cost estimates. If Generation does not receive license renewal on a particular unit, the increase tothe ARO may be mitigated by Generation’s ability to delay ultimate decommissioning activities under a SAFSTOR method of decommissioning. 102Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDiscount 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. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations andare measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted futurecash flows relating to the ARO are treated as a modification of an existing ARO and, therefore, are measured using the average historical CARFRrates used in creating the initial ARO cost layers. 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 $8.2 billion to approximately $8.5billion. 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, 2015 at fair value of approximately $10.3 billion and have an estimated targeted annual pre-tax return of 6.1% 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 2014 CARFRs rather than the 2015 CARFRs in performing its thirdquarter 2015 ARO update, Generation would have increased the ARO by approximately $940 million as compared to the actual increase to theARO of $831 million; and ii) if the CARFR used in performing the third quarter 2015 ARO update (which also reflected increases in the amountsand changes to the timing of projected cash flows) was increased by 100 basis points or decreased by 50 basis points, the ARO would haveincreased by $100 million and $1.2 billion, respectively, as compared to the actual increase of $831 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. 103Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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, 2015 Cost escalation studies Uniform increase in escalation rates of 50 basis points $1,600 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 20 percent $1,420 Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of theSAFSTOR scenario by 10 percentage points $410 Increase the likelihood of the SAFSTOR scenario by 20 percentage points and decrease the likelihood ofthe Delayed DECON scenario by 20 percentage points $(240) 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 $540 Extend the estimated date for DOE acceptance of SNF to 2030 $(20) Extend the estimated date for DOE acceptance of SNF to 2030 coupled with an increase in discount ratesof 100 basis points $(480) Extend the estimated date for DOE acceptance of SNF to 2030 coupled with a decrease in discount ratesof 50 basis points $270 (a)The Delayed DECON scenario is currently assumed to be the most likely decommissioning approach for a majority of Exelon’s nuclear plants. For more information regarding accounting for nuclear decommissioning obligations, see Note 1—Significant Accounting Policies, Note 9—Implications of Potential Early Plant Retirements and Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated FinancialStatements. Goodwill (Exelon and ComEd) As of December 31, 2015, 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. Entities 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 104(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsqualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than itscarrying amount, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to itscarrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The secondstep requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance 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. Application of the goodwill impairment test requires management judgment, includingthe identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combinationof a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discountand growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s business and the fairvalue of debt. In applying the second step (if needed), management must estimate the fair value of specific assets and liabilities of the reportingunit. See Note 1—Significant Accounting Policies, Note 11—Intangible Assets and Note 15—Income Taxes of the Combined Notes toConsolidated 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, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respectto the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgmentsmade in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful lifeof each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as throughdepreciation and amortization expense. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated FinancialStatements 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 expected realization of the underlying cash flows. Amortization expense and income arerecorded through purchased power and fuel expense or operating revenues. Refer to Note 4—Mergers, Acquisitions, and Dispositions and Note 11—Intangible Assets of the Combined Notes to Consolidated Financial Statements for further discussion. Impairment of Long-lived Assets (Exelon, Generation, ComEd, PECO and BGE) Exelon, Generation, ComEd, PECO and BGE regularly monitor and evaluate their long-lived assets and asset groups, excluding goodwill, forimpairment when circumstances indicate the carrying value of those assets may not be recoverable. Indicators of potential impairment mayinclude a deteriorating business climate, including decline in energy prices, condition of the asset, specific regulatory disallowance, or plans todispose of a long-lived asset significantly before the end of its useful life, among others. 105Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates offuture 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 the cash flows of other assets and liabilities.For the generation business, the lowest level of independent cash flows is determined by the evaluation of several factors, including thegeographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets orliabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cashflows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on thebalance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-termbasis 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 for a long-lived asset orasset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flowanalysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excessof the carrying amount of the long-lived asset or asset group over its fair value less costs to sell. The fair value of the long-lived asset or assetgroup is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated futurecash flows generated by the assets and market discount rates. Events and circumstances often do not occur as expected and there will usuallybe differences between prospective financial information and actual results, and those differences may be material. Accordingly, to the extent thatany 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 assets or liabilities, as well as reduce the current period earnings by the amount of the impairment. Generation evaluates natural gas and oil upstream properties on a quarterly basis to determine if they are impaired. Impairment indicators fornatural gas and oil upstream properties are present if there are no firm plans to continue drilling, lease expiration is at risk, historical experienceindicates a decline in carrying value below fair value or the price of the underlying commodity significantly declines. Generation evaluates its equity method investments and other investments in debt and equity securities to determine whether or not they areimpaired based on whether the investment has experienced a decline in value that is not temporary in nature. Exelon 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 106Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, that takes into considerationsignificant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over theirremaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energyand capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful livesof the plants. The estimated fair values also reflect the cash flows associated with the service contracts associated with the plants given that amarket participant would take into consideration all of the terms and conditions contained in the lease agreements. 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 if an event, regulatory 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 remaining useful lives of the stations, whichassume a license renewal extension of the Conowingo and Muddy Run operating licenses. A change in depreciation estimates resulting fromGeneration’s extension or reduction of the estimated service lives could have a significant effect on Generation’s results of operations. Generation completed a depreciation rate study during the first quarter of 2015, which resulted in the implementation of new depreciationrates effective January 1, 2015. 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. 107Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 is required to file a depreciation rate study at least every five years with the PAPUC. In March 2015, 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 1,2015 for electric transmission assets, July 1, 2015 for gas distribution assets and January 1, 2016 for electric distribution 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 Employee Benefits (Exelon, Generation, ComEd, PECO and BGE) Exelon sponsors defined benefit pension plans and other postretirement employee benefit plans for substantially all Generation, ComEd,PECO, BGE and BSC employees. See Note 17—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additionalinformation regarding the accounting for the defined benefit pension plans and other postretirement benefit plans. The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit pension and other 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. Pension 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 17—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%, 7.00% and7.50% for 2015, 2014 and 2013, respectively. The weighted average EROA assumption used in calculating other postretirement benefit costs was6.46%, 6.59% and 6.45% in 2015, 2014 and 2013, 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 108Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsfixed income securities and alternative investments within the pension asset portfolio in order to achieve a balanced portfolio of liability hedgingand return-generating assets. See Note 17—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additionalinformation regarding Exelon’s asset allocations. Exelon used an EROA of 7.00% and 6.71% to estimate its 2016 pension and otherpostretirement 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, 2015 were 0.29% and0.80%, respectively, compared to an expected long-term return assumption of 7.00% and 6.46%, respectively. Discount Rate. The discount rate used to determine the majority of pension and other postretirement benefit obligations was 4.29% atDecember 31, 2015. The discount rates at December 31, 2015 represent weighted-average rates for the majority of pension and otherpostretirement benefit plans. At December 31, 2015 and 2014, the discount rates were determined by developing a spot rate curve based on theyield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the relatedpension and other postretirement benefit obligations. The spot rates are used to discount the estimated distributions under the pension and otherpostretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes ananalytical 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 3.68% to 4.43% to estimate its 2016 pension and other postretirement benefit costs. Health Care Reform Legislation. In March 2010, the Health Care Reform Acts were signed into law, which contain a number of provisionsthat impact retiree health care plans provided by employers, including a provision that imposes an excise tax on certain high-cost plans wherebypremiums paid over a prescribed threshold will be taxed at a 40% rate. Additional legislation was passed in December 2015 that made somechanges to the law, including moving the implementation date of the excise tax from 2018 to 2020. Although the excise tax does not go into effectuntil 2020, accounting guidance requires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. Theapplication of the legislation is still unclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Certain keyassumptions are required to estimate the impact of the excise tax on Exelon’s other postretirement benefit obligation, including projected inflationrates (based on the CPI). 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 109Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentshave a cap on cost growth. Accounting guidance requires that annual health care cost estimates be developed using past and present health carecost trends (both for Exelon and across the broader economy), as well as expectations of health care cost escalation, changes in health careutilization and delivery patterns, technological advances and changes in the health status of plan participants. Therefore, the trend rate assumptionis subject to significant uncertainty. Exelon assumed an initial health care cost trend rate of 6.00% for 2015, decreasing to an ultimate health carecost 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 uses a mortality base table for itsaccounting valuation that is consistent with the IRS required table for funding (referred to as RP-2000). Exelon has a substantial employeepopulation that provides a credible basis for mortality evaluation. Exelon is utilizing the Scale BB 2-Dimensional improvement scale with long-termimprovements of 0.75% for its mortality improvement assumption. Sensitivity 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 2015 cost: Discount rate 0.5% $(69) $(19) $(88) (0.5)% 83 30 113 EROA 0.5% (73) (11) (84) (0.5)% 73 11 84 Health care cost trend rate 1.00% N/A 12 12 (1.00)% N/A (9) (9) Change in benefit obligation atDecember 31, 2015: Discount rate 0.5% (1,042) (249) (1,291) (0.5)% 1,210 289 1,499 Health care cost trend rate 1.00% N/A 100 100 (1.00)% N/A (89) (89) (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 11.9 years, 11.8 years and 11.8 years for the years ended December 31, 2015, 2014 and 2013, 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 110 (a)(b) (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsparticipants related to benefit eligibility age was 10.8 years, 9.1 years and 8.7 years for the years ended December 31, 2015, 2014 and 2013,respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 9.7 years, 10.1years and 9.8 years for the years ended December 31, 2015, 2014 and 2013, 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 accrued credits that have been deferred because it is probable such amounts will be returned to customers through futureregulated rates; or (2) billings in advance of expenditures for approved regulatory programs. As of December 31, 2015, Exelon, ComEd, PECO andBGE have concluded that the operations of ComEd, PECO and BGE meet the criteria to apply the authoritative guidance. If it is concluded in afuture period that a separable portion of those operations no longer meets the criteria of this guidance, Exelon, ComEd, PECO and BGE would berequired to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the Consolidated Statements ofOperations and could be material. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additionalinformation regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon, ComEd, PECO and BGE. For each regulatory jurisdiction in which they conduct business, Exelon, ComEd, PECO and BGE assess whether the regulatory assets 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. 111Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAccounting 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 Registrants’ derivativeactivities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 13—Derivative Financial Instruments of the Combined Notesto 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 remained probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and wasreclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. None of 112Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsConstellation’s designated cash flow hedges for commodity transactions prior to the Constellation merger were re-designated as cash flow hedges.The effect of this decision is that all economic hedges for commodities are recorded at fair value through earnings for the combined company. Inaddition, for energy-related derivatives entered into for proprietary trading purposes, changes in the fair value of the derivatives are recognized inearnings each period. For economic hedges that are not designated for hedge accounting for ComEd, PECO and BGE, changes in the fair valueeach 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 on an accrual basis ofaccounting. Determining whether a contract qualifies for the normal purchases and normal sales exception requires that management exercisejudgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualificationand documentation requirements. Revenues and expenses on contracts that qualify as normal purchases and normal sales are recognized whenthe underlying physical transaction is completed. Contracts which qualify for the normal purchases and normal sales exception are those for whichphysical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and isnot financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd’s energy procurement process,PECO’s full requirement contracts and block contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreementsand all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives qualify for the normal purchases and normalsales 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 models that take into account inputs such as contractterms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness andcredit spread. For derivatives that trade in liquid 113Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsmarkets, such as generic forwards, swaps and options, the model inputs are generally observable. Such instruments are categorized in Level 2.For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable andunobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants woulduse in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Suchinstruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider nonperformance risk, includingcredit risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in itsassessment of nonperformance risk, including credit risk. The impacts of credit and nonperformance risk to date have generally not been materialto 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 may use forward-starting interest rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financingsand floating to fixed swaps for project financing. In addition, Generation enters into interest rate derivative contracts to economically hedge riskassociated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between theeconomic hedge and proprietary trading activity is driven by the corresponding characterization of the underlying commodity position that givesrise to the interest rate exposure. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or change inmarket interest rates. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S.dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. The fair value of the agreements iscalculated by discounting the future net cash flows to the present value based on the terms and conditions of the agreements and the forwardinterest rate and foreign exchange curves. As these inputs are based on observable data and valuations of similar instruments, the interest rateand foreign exchange derivatives are primarily categorized in Level 2 in the fair value hierarchy. Certain exchange based interest rate derivativesthat are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 12—Fair Value of Financial Assetsand Liabilities and Note 13—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. 114Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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, 2015 and 2014 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of taxmatters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material.See Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding taxes. Accounting for Loss Contingencies (Exelon, Generation, ComEd, PECO and BGE) In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events 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 23—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. 115Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsRevenue Recognition (Exelon, Generation, ComEd, PECO and BGE) Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activitiesincluding: the sale of energy and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets(wholesale and retail); the sale and delivery of electricity and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services. The appropriate accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable 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 normal purchases and normal sales (NPNS) of commoditiesthat will be physically delivered, sales to utility customers under regulated service tariffs and spot-market sales, including settlements withindependent 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, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilledcommodity receivables are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type ofcustomers scheduled for each meter reading date would also have an effect on the measurement of unbilled revenue; however, total operatingrevenues 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 116Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentssheet dates, ComEd has recorded its best estimates of the distribution revenue impact resulting from changes in rates that ComEd believes areprobable of approval by the ICC in accordance with the formula rate mechanism. Estimates are based upon actual costs incurred and investmentsin rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff.The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE and actions byregulators 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. 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, PECOand BGE estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for eachcompany to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar creditquality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates appliedto the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment.ComEd, PECO and BGE customers’ accounts are generally considered delinquent if the amount billed is not received by the time the next bill isissued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent with approved regulatoryrequirements. ComEd’s, PECO’s and BGE’s provisions for uncollectible accounts will continue to be affected by changes in volume, prices andeconomic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 6—Accounts Receivable of theCombined 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, 2015, 2014 and 2013 set forth belowinclude intercompany transactions, which are eliminated in Exelon’s consolidated financial statements. Net Income Attributable to Common Shareholders by Registrant 2015 2014 Favorable(unfavorable)2015 vs. 2014variance 2013 Favorable(unfavorable)2014 vs. 2013variance Exelon $2,269 $1,623 $646 $1,719 $(96) Generation 1,372 835 537 1,070 (235) ComEd 426 408 18 249 159 PECO 378 352 26 388 (36) BGE 275 198 77 197 1 117Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015 2014 Favorable(unfavorable)2015 vs. 2014variance 2013 Favorable(unfavorable)2014 vs. 2013variance Operating revenues $19,135 $17,393 $1,742 $15,630 $1,763 Purchased power and fuel expense 10,021 9,925 (96) 8,197 (1,728) Revenue net of purchased power and fuel expense 9,114 7,468 1,646 7,433 35 Other operating expenses Operating and maintenance 5,308 5,566 258 4,534 (1,032) Depreciation and amortization 1,054 967 (87) 856 (111) Taxes other than income 489 465 (24) 389 (76) Total other operating expenses 6,851 6,998 147 5,779 (1,219) Equity in (losses) earnings of unconsolidated affiliates — (20) 20 10 (30) Gain on sales of assets 12 437 (425) 13 424 Gain on consolidation and acquisition of businesses — 289 (289) — 289 Operating income 2,275 1,176 1,099 1,677 (501) Other income and (deductions) Interest expense (365) (356) (9) (357) 1 Other, net (60) 406 (466) 355 51 Total other income and (deductions) (425) 50 (475) (2) 52 Income before income taxes 1,850 1,226 624 1,675 (449) Income taxes 502 207 (295) 615 408 Equity in losses of unconsolidated affiliates (8) — 8 — — Net income 1,340 1,019 321 1,060 (41) Net income (loss) attributable to noncontrolling interest (32) 184 (216) (10) 194 Net income attributable to membership interest $1,372 $835 $537 $1,070 $(235) (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, the financial results include CENG’s results ofoperations on a fully consolidated basis.(b)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. Net Income Attributable to Membership Interest Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Generation’s net income attributable to membership interestincreased compared to the same period in 2014 primarily due to higher revenue net of purchase power and fuel expense and lower operating andmaintenance expense; partially offset by the absence of the 2014 gains recorded on the sales of Generation’s ownership interest in generatingstations, the absence of the 2014 gain recorded upon the consolidation of CENG, decreased other income and increased income tax expense. Theincrease in 118 (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsrevenue, net of purchase power and fuel expense was primarily due to the inclusion of CENG’s results on fully consolidated basis in 2015, thebenefit of lower cost to serve load (including the absence of higher procurement costs for replacement power in 2014), the cancellation of the DOEspent nuclear fuel disposal fee, increased capacity prices, the inclusion of Integrys’ results in 2015, favorability from portfolio managementoptimization activities, increased load served, and mark-to-market gains in 2015 compared to mark-to-market losses in 2014, partially offset bylower margins resulting from the 2014 sale of generating assets, lower realized energy prices, and the absence of the 2014 fuel optimizationopportunities in the South region due to extreme cold weather. The decrease in operating and maintenance expense was largely due to thereduction of long-lived asset impairment charges in 2015 versus 2014, partially offset by increased labor, contracting and materials expense due tothe inclusion of CENG’s results on a fully consolidated basis in 2015 and increased energy efficiency projects. The decrease in other income isprimarily the result of the change in realized and unrealized gains and losses on NDT fund investments in 2015 as compared to 2014. 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 on a fully consolidated basis beginning April 1, 2014 and impairment charges related to 1) generating assetsheld-for-sale, 2) certain Upstream assets, and 3) wind generating assets. The increase in revenue, net of purchased power and fuel expense wasprimarily due to the inclusion of CENG’s results beginning April 1, 2014, a decrease in fuel costs related to the cancellation of DOE spent nuclearfuel disposal fees, an increase in capacity prices, and favorable portfolio management activities in the New England and South regions, partiallyoffset by lower realized energy prices related to executing Exelon’s ratable hedging strategy, higher procurement costs for replacement power dueto extreme cold weather in the first quarter of 2014, and unrealized mark-to-market losses in 2014. The increase in other income is primarily theresult of increased realized and unrealized gains on NDT fund investments. Revenue Net of Purchased Power and Fuel Expense The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in differentgeographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provideelectricity through various distribution channels (wholesale and retail). Generation’s hedging strategies and risk metrics are also aligned with thesesame geographic regions. Descriptions of each of Generation’s six reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware,the District of Columbia and parts of Pennsylvania and North Carolina. • Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan,Kentucky and Tennessee, and the United States footprint of MISO excluding MISO’s Southern Region, which covers all or most ofNorth Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio notcovered 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. 119Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 • 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 Power Regions: • 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: natural gas, as well as other miscellaneousbusiness activities that are not significant to Generation’s overall operating revenues or results of operations. Further, the following activities arenot allocated to a region, and are reported in the table below in Other: unrealized mark-to-market impact of economic hedging activities;amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; and othermiscellaneous revenues. Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power andfuel expense, which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd,PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy andancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements. For the years ended December 31, 2015 compared to 2014 and December 31, 2014 compared to 2013, Generation’s revenue net ofpurchased power and fuel expense by region were as follows: 2015 vs. 2014 2014 vs. 2013 2015 2014 Variance % Change 2013 Variance % Change Mid-Atlantic $3,571 $3,431 $140 4.1% $3,270 $161 4.9% Midwest 2,892 2,599 293 11.3% 2,586 13 0.5% New England 461 351 110 31.3% 185 166 89.7% New York 634 483 151 31.3% (4) 487 n.m. ERCOT 293 317 (24) (7.6)% 436 (119) (27.3)% Other Power Regions 250 327 (77) (23.5)% 201 126 62.7% Total electric revenue net of purchased power and fuelexpense 8,101 7,508 593 7.9% 6,674 834 12.5% Proprietary Trading 1 42 (41) (97.6)% (8) 50 n.m. Mark-to-market gains (losses) 257 (591) 848 n.m. 504 (1,095) n.m. Other 755 509 246 48.3% 263 246 93.5% Total revenue net of purchased power and fuel expense $9,114 $7,468 $1,646 22.0% $7,433 $35 0.5% 120 (a)(b)(e) (c) (a)(e) (d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, beginning April 1, 2014, the financial results include CENG’s results on a fullyconsolidated basis.(b)Results of transactions with PECO and BGE are included in the Mid-Atlantic region.(c)Results of transactions with ComEd are included in the Midwest region.(d)Other represents activities not allocated to a region. See text above for a description of included activities. Also includes an $8 million increase to RNF, a $124 million decrease toRNF, and a $488 million decrease to RNF for the amortization of intangible assets related to energy contracts for the years ended December 31, 2015, 2014, and 2013,respectively.(e)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. See Note 26—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information. Generation’s supply sources by region are summarized below: 2015 vs. 2014 2014 vs. 2013 Supply Source (GWh) 2015 2014 Variance % Change 2013 Variance % Change Nuclear Generation Mid-Atlantic 63,283 58,809 4,474 7.6% 48,881 9,928 20.3% Midwest 93,422 94,000 (578) (0.6)% 93,245 755 0.8% New York 18,769 13,645 5,124 37.6% — 13,645 n.m. Total Nuclear Generation 175,474 166,454 9,020 5.4% 142,126 24,328 17.1% Fossil and Renewables Mid-Atlantic 2,774 11,025 (8,251) (74.8)% 11,714 (689) (5.9)% Midwest 1,547 1,372 175 12.8% 1,478 (106) (7.2)% New England 2,983 5,233 (2,250) (43.0)% 10,896 (5,663) (52.0)% New York 3 4 (1) (25.0)% — 4 n.m. ERCOT 5,763 7,164 (1,401) (19.6)% 6,453 711 11.0% Other Power Regions 7,848 7,955 (107) (1.3)% 6,664 1,291 19.4% Total Fossil and Renewables 20,918 32,753 (11,835) (36.1)% 37,205 (4,452) (12.0)% Purchased Power Mid-Atlantic 8,160 6,082 2,078 34.2% 14,092 (8,010) (56.8)% Midwest 2,325 2,004 321 16.0% 4,408 (2,404) (54.5)% New England 24,309 12,354 11,955 96.8% 7,655 4,699 61.4% New York — 2,857 (2,857) (100.0)% 13,642 (10,785) (79.1)% ERCOT 10,070 8,651 1,419 16.4% 13,459 (4,808) (35.7)% Other Power Regions 16,728 14,795 1,933 13.1% 14,931 (136) (0.9)% Total Purchased Power 61,592 46,743 14,849 31.8% 68,187 (21,444) (31.4)% Total Supply/Sales by Region Mid-Atlantic 74,217 75,916 (1,699) (2.2)% 74,687 1,229 1.6% Midwest 97,294 97,376 (82) (0.1)% 99,131 (1,755) (1.8)% New England 27,292 17,587 9,705 55.2% 18,551 (964) (5.2)% New York 18,772 16,506 2,266 13.7% 13,642 2,864 21.0% ERCOT 15,833 15,815 18 0.1% 19,912 (4,097) (20.6)% Other Power Regions 24,576 22,750 1,826 8.0% 21,595 1,155 5.3% Total Supply/Sales by Region 257,984 245,950 12,034 4.9% 247,518 (1,568) (0.6)% (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 the year ended December 31, 2015 includes physical volumes of 14,646 GWh in Mid-Atlantic and 18,769 GWh in NewYork for CENG and for the year ended December 31, 2014 includes physical volumes of 11,409 GWh in Mid-Atlantic and 13,645 GWh in New York for CENG. Prior to theintegration date of April 1, 2014, CENG volumes were included in purchased power. 121 (a) (a) (b) (b) (c) (d)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)Purchased power includes physical volumes of 2,489 GWh and 12,067 GWh in the Mid-Atlantic and 2,857 GWh and 12,165 GWh in New York as a result of the PPA with CENGfor the years ended December 31, 2014 and 2013, respectively. Since the integration date of April 1, 2014, CENG volumes are included in nuclear generation.(c)Excludes physical proprietary trading volumes of 7,310 GWh, 10,571 GWh, and 8,762 GWh for the years ended December 31, 2015, 2014, and 2013, respectively.(d)Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. Mid-Atlantic Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The increase in revenue net of purchased power and fuelexpense in the Mid-Atlantic of $140 million was primarily due to the inclusion of CENG’s results on a fully consolidated basis for the full year in2015, the benefit of lower cost to serve load (which includes the absence of higher procurement costs for replacement power due to extreme coldweather in the first quarter of 2014), increased load volumes served, higher nuclear volumes, the cancellation of the DOE spent nuclear fueldisposal fee, and favorability from portfolio management optimization activities, partially offset by lower capacity revenues, and lower generationvolumes due to the sale of generating assets. 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 $161 million was primarily due to the consolidation of CENG, the cancellation of the DOE spent nuclear fueldisposal fees in 2014, and favorable portfolio management optimization activities, partially offset by higher procurement costs for replacementpower, lower nuclear volumes (excluding CENG), lower capacity revenues, and lower realized energy prices related to executing Generation’sratable hedging strategy. Midwest Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The increase in revenue net of purchased power and fuelexpense in the Midwest of $293 million was primarily due to higher capacity revenues, increased load volumes served, the inclusion of Integrys’results in 2015, the cancellation of the DOE spent nuclear fuel disposal fee in 2014, and favorability from portfolio management optimizationactivities, partially offset by lower nuclear volumes. 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 $13 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. New England Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The increase in revenue net of purchased power and fuelexpense in New England of $110 million was primarily due to the benefit of lower cost to serve load, increased load volumes served, the inclusionof Integrys’ results in 2015, and favorability from portfolio management optimization activities, partially offset by lower generation volumes due tothe sale of a generating asset. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in revenue net of purchased power and fuelexpense in New England of $166 million was primarily due to higher realized energy prices and favorable impacts from the restructuring of a fuelsupply contract, partially offset by lower generation volume. New York Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $151 million increase in revenue net of purchased powerand fuel expense in New York was primarily due to the 122Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsinclusion of CENG’s results on a fully consolidated basis for the full year in 2015, increased nuclear volumes and the inclusion of Integrys’ resultsin 2015, partially offset by lower realized energy prices and decreased capacity revenues. 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. ERCOT Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $24 million decrease in revenue net of purchased powerand fuel expense in ERCOT was primarily due to lower realized energy prices and a decrease in generation volumes due to the sale of agenerating asset, partially offset by the absence of higher procurement costs for replacement power in 2014 and decreased fuel costs. 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. Other Power Regions Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The decrease in revenue net of purchased power and fuelexpense in Other Power Regions of $77 million was primarily due to the amortization of contracts recorded at fair value associated with prioracquisitions, lower realized energy prices, the absence of the 2014 fuel optimization opportunities, partially offset by increased generation frompower purchase agreements, and decreased fuel costs. 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 Power Regions was primarily due to higher generation volumes and higher realized energy prices. Proprietary Trading Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $41 million decrease in revenue net of purchased powerand fuel expense in Proprietary trading was primarily due to the absence of gains on congestion trading products. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The $50 million increase in revenue net of purchased powerand fuel expense in Proprietary trading was primarily due to gains on congestion trading products. Mark-to-market Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposureto these fluctuations. See Note 12—Fair Value of Financial 123Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAssets and Liabilities and Note 13—Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements forinformation on gains and losses associated with mark-to-market derivatives. Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Mark-to-market gains on economic hedging activities were$257 million in 2015 compared to losses of $591 million in 2014. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Mark-to-market losses on economic hedging activities were$591 million in 2014 compared to gains of $504 million in 2013. Other Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $246 million increase in other revenue net of purchasedpower and fuel was primarily due to the amortization of energy contracts recorded at fair value associated with prior acquisitions, the inclusion ofIntegrys’ gas results in 2015, and an increase in distributed generation and energy efficiency activity. See Note 11—Intangible Assets of theCombined Notes to Consolidated Financial Statements for information regarding energy contract intangibles. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The $246 million increase in other revenue net of purchasedpower and fuel was primarily due to the amortization of energy contracts recorded at fair value associated with prior acquisitions, partially offset bya loss on gas inventory from lower of cost or market adjustments in 2014. See Note 11—Intangible Assets of the Combined Notes to ConsolidatedFinancial Statements for information regarding energy contract intangibles. Nuclear Fleet Capacity Factor The following table presents nuclear fleet operating data for 2015, as compared to 2014 and 2013, 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. Generation considers capacity factor useful measure to analyze thenuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided inaccordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’presentations or be more useful than the GAAP information provided elsewhere in this report. 2015 2014 2013 Nuclear fleet capacity factor 93.7% 94.3% 94.1% (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, 2015 Compared to Year Ended December 31, 2014. The nuclear fleet capacity factor, which excludes Salem,decreased in 2015 compared to 2014 primarily due to a higher number of refueling outage days and non-outage energy losses, partially offset by alower number of unplanned outage days. For 2015 and 2014, planned refueling outage days totaled 290 and 275, respectively, and non-refuelingoutage days totaled 82 and 92, respectively 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 124 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentswere greater in 2014 as compared to 2013, the larger capacity units were online for more days in 2014. Additionally, with the addition of the CENGnuclear facilities there were more days offline in 2014 associated with units where Exelon’s ownership percentage diminishes the impact oncapacity factor. For 2014 and 2013, planned refueling outage days totaled 275 and 233, respectively, and non-refueling outage days totaled 92 and75, respectively. Operating and Maintenance Expense The changes in operating and maintenance expense for 2015 compared to 2014, consisted of the following: Increase(Decrease) Impairment and related charges of certain generating assets $(651) Maryland merger commitments (44) Merger and integration costs (28) Midwest Generation bankruptcy charges (14) Decrease in asbestos bodily injury reserve (12) ARO update 8 Regulatory fees and assessments 10 Pension and non-pension postretirement benefits expense 15 Corporate allocations 16 Accretion expense 18 Nuclear refueling outage costs, including the co-owned Salem plant 64 Labor, other benefits, contracting and materials 323 Other 37 Decrease in operating and maintenance expense $(258) (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the operating results include CENG’s results of operations on a fully consolidatedbasis from April 1, 2014 through December 31, 2014 and for the entire year in 2015.(b)Primarily relates to impairments of certain generating assets held-for-sale, Upstream assets, and wind generating assets during 2014 that did not reoccur in 2015.(c)Reflects an increased share of corporate allocated costs primarily due to the inclusion of CENG beginning April 1, 2014.(d)Reflects the unfavorable impacts of increased nuclear outages in 2015.(e)Reflects an increase of labor, other benefits, contracting and materials costs primarily due to the inclusion of CENG on a fully consolidated basis in 2015. Also includes cost ofsales of our other business activities that are not allocated to a region. 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 $1,032 125(a)(b)(c)(d)(e)(a)(b)(c)(d) (e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 inclusion of CENG beginning April 1, 2014.(e)Reflects the impact of increased nuclear outage days primarily due to the inclusion of CENG beginning April 1, 2014. Depreciation and Amortization Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The increase in depreciation and amortization expense wasprimarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015, increased nuclear decommissioning amortization, and anincrease in ongoing capital expenditures. 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. Taxes Other Than Income Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The increase in taxes other than income was primarily due tothe inclusion of CENG’s results on a fully consolidated basis in 2015. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in taxes other than income was primarily due tothe inclusion of CENG’s results on a fully consolidated basis beginning April 1, 2014. Equity in Earnings (Losses) of Unconsolidated Affiliates Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. 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. 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. Gain (Loss) on Sales of Assets Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The decrease in gain (loss) on sales of assets in primarilyrelated to the absence of $411 million of gains recorded on the sale of Generation’s ownership interests in Safe Harbor Water Power Corporation,Fore River and West Valley generating stations in 2014. Refer to Note 4—Mergers, Acquisitions and Dispositions in the Combined Notes toConsolidated Financial Statements for additional information. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. The increase in gain (loss) on sales of assets is primarilyrelated to $411 million of gains recorded on the sale of 126Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 ownership interests in Safe Harbor Water Power Corporation, Fore River and West Valley generating stations in 2014. Refer to Note 4—Mergers, Acquisitions and Dispositions in the Combined Notes to Consolidated Financial Statements for additional information. Gain on Consolidation and Acquisition of Businesses Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The decrease in gain on consolidation and acquisition ofbusinesses reflects the absence of a $261 million gain upon consolidation of CENG resulting from the difference in fair value of CENG’s netassets as of April 1, 2014 and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing transactions between Generation and CENG recorded in 2014, and the absence of a $28 million bargain-purchase gain related to theIntegrys acquisition recorded in 2014. Interest Expense The changes in interest expense for 2015 compared to 2014 and 2014 compared to 2013 consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Interest expense on long-term debt $53 $33 Interest expense on interest rate swaps 22 4 Interest expense on tax settlements (37) (21) Other interest expense (29) (17) Increase (decrease) in interest expense, net $9 $(1) Other, Net Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The decrease in Other, net primarily reflects the net decreasein realized and unrealized gains related to the NDT fund investments of Generation’s Non-Regulatory Agreement Units as described in the tablebelow. Other, net also reflects $(22) million and $67 million for the year ended December 31, 2015 and 2014, respectively, related to thecontractual elimination of income tax expense associated with the NDT fund investments of the Regulatory Agreement Units. Refer to Note 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT fundinvestments. 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 tax returns and the increased net realized and unrealized gains related to theNDT fund investments of Generation’s Non-Regulatory Agreement Units compared to net realized and unrealized gains in 2013, as described in thetable below. Other, net also reflects $67 million and $122 million for the year ended December 31, 2014 and 2013, respectively, related to thecontractual elimination of income tax expense (benefit) associated with the NDT fund investments of the Regulatory Agreement Units. Refer toNote 15—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT fundinvestments. The following table provides unrealized and realized gains (losses) on the NDT fund investments of the Non-Regulatory Agreement Unitsrecognized in Other, net for 2015, 2014 and 2013: 2015 2014 2013 Net unrealized (losses) gains on decommissioning trust funds $(197) $134 $146 Net realized gains on sale of decommissioning trust funds $66 $77 $24 127Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Generation’s effective income tax rates for the years ended December 31, 2015, 2014 and 2013 were 27.1%, 16.9% and 36.7%,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 2015 2014 Favorable(Unfavorable)2015 vs.2014Variance 2013 Favorable(Unfavorable)2014 vs.2013Variance Operating revenue $4,905 $4,564 $341 $4,464 $100 Purchased power expense 1,319 1,177 (142) 1,174 (3) Revenue net of purchased power expense 3,586 3,387 199 3,290 97 Other operating expenses Operating and maintenance 1,567 1,429 (138) 1,368 (61) Depreciation and amortization 707 687 (20) 669 (18) Taxes other than income 296 293 (3) 299 6 Total other operating expenses 2,570 2,409 (161) 2,336 (73) Gain on sales of assets 1 2 (1) — 2 Operating income 1,017 980 37 954 26 Other income and (deductions) Interest expense, net (332) (321) (11) (579) 258 Other, net 21 17 4 26 (9) Total other income and (deductions) (311) (304) (7) (553) 249 Income before income taxes 706 676 30 401 275 Income taxes 280 268 (12) 152 (116) Net income $426 $408 $18 $249 $159 (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 isa useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery 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.(b)For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverablecosts fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings). Net Income Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. ComEd’s Net income for the year ended December 31, 2015was higher than the same period in 2014 primarily due to increased electric distribution and transmission formula rate earnings (reflecting theimpacts of increased capital investment, partially offset by lower allowed electric distribution ROE), partially offset by unfavorable weather andvolume. 128 (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2014 Compared to Year Ended December 31, 2013. ComEd’s Net income for the year ended December 31, 2014was higher than the same period in 2013 primarily due to the 2013 remeasurement of Exelon’s like-kind exchange tax position and increasedelectric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment), partially offset by unfavorableweather. 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. Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31,2015, 2014 and 2013, consisted of the following: For the Years Ended December 31, 2015 2014 2013 Electric 76% 80% 81% Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2015, 2014 and 2013consisted of the following: December 31, 2015 December 31, 2014 December 31, 2013 Number ofcustomers % of totalretailcustomers Number ofcustomers % of totalretailcustomers Number ofcustomers % of totalretailcustomers Electric 1,655,400 42% 2,426,900 63% 2,630,200 68% Under an Illinois law allowing municipalities to arrange the purchase of electricity for their participating residents, the City of Chicagopreviously participated in ComEd’s customer choice program and arranged the purchase of electricity from Constellation (formerly Integrys), forthose participating residents. In September 2015, the City of Chicago discontinued its participation in the customer choice program and many ofthose participating residents resumed their purchase of electricity from ComEd. ComEd’s Operating revenue has increased as a result of the Cityof Chicago switching, but that increase is fully offset in Purchased power expense. 129Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 ComEd’s Revenue net of purchased power expense for the year ended December 31, 2015 compared to the same period in2014, and for the year ended December 31, 2014 compared to the same period in 2013, consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Weather $(16) $(16) Volume (22) — Electric distribution revenue 180 (2) Transmission revenue 48 30 Regulatory required programs (1) 52 Uncollectible accounts recovery, net 27 41 Pricing and customer mix (4) 5 Revenue subject to refund 9 (9) Other (22) (4) Increase in revenue net of purchased power $199 $97 Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in othermonths are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage. Conversely, mildweather reduces demand. For the years ended December 31, 2015 and 2014, unfavorable weather conditions reduced Operating revenue net ofpurchased power expense when compared to the prior years. 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, 2015, 2014 and 2013 consisted of the following: For the Years EndedDecember 31, % Change Heating and Cooling Degree-Days 2015 2014 Normal 2015 vs. 2014 2015 vs. Normal Heating Degree-Days 6,091 7,027 6,341 (13.3)% (3.9)% Cooling Degree-Days 806 799 842 0.9% (4.3)% For the Years EndedDecember 31, % Change Heating and Cooling Degree-Days 2014 2013 Normal 2014 vs. 2013 2014 vs. 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. Revenue net of purchased power expense decreased as a result of lower delivery volume, exclusive of the effects of weather, forthe year ended December 31, 2015, reflecting decreased average usage per residential customer and the impacts of energy efficiency programs,as compared to the same period in 2014. For the year ended December 31, 2014, Revenue net of purchased power expense remained relativelyconsistent, as compared to the same period in 2013. Electric Distribution Revenue. EIMA provides for a performance-based formula rate tariff, which requires an annual reconciliation of therevenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under EIMA,electric distribution 130Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsrevenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, allowed ROE, and other billingdeterminants. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points, subject to a collar of plus orminus 50 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on revenue. During the year endedDecember 31, 2015, electric distribution revenue increased $180 million, primarily due to higher Operating and maintenance expense and increasedcapital investment, partially offset by lower allowed ROE due to decreased treasury rates. During the year ended December 31, 2014, electricdistribution revenue decreased $2 million, primarily due to lower Operating and maintenance expense resulting from certain OPEB plan designchanges, partially offset by increased capital investment. See Operating and Maintenance Expense below and Note 3—Regulatory Matters of theCombined 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 theunderlying costs, investments being recovered and other billing determinants, such as the highest daily peak load from the previous calendar year.During the years ended December 31, 2015 and 2014, ComEd recorded increased transmission revenue primarily due to higher Operating andmaintenance expense and increased capital investment. See Operating and Maintenance Expense below and Note 3—Regulatory Matters of theCombined 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 incurredfor regulatory programs such as ComEd’s energy efficiency and demand response and purchased power administrative costs. The riders aredesigned to provide full and current cost recovery. An equal and offsetting amount has been included in Operating and maintenance expense. SeeOperating and maintenance expense discussion below for additional information on included programs. Uncollectible Accounts Recovery, Net. Uncollectible accounts recovery, net, represents recoveries under ComEd’s uncollectible accountstariff. See Operating and maintenance expense discussion below for additional information on this tariff. Pricing and Customer Mix. For the year ended December 31, 2015, the decrease in Revenue net of purchased power as a result of pricingand customer mix is primarily attributable to lower overall effective rates due to increased usage across all major customer classes and change incustomer mix. For the year ended December 31, 2014, the increase in Revenue net of purchased power as a result of pricing and customer mix isprimarily attributable to higher overall effective rates due to decreased usage across all major customer classes and change in customer mix. Revenue Subject to Refund. ComEd records revenue subject to refund based upon its best estimate of customer collections that may berequired to be refunded. Revenue net of purchase power expense was higher for the year ended December 31, 2015, due to the one-time revenuerefund recorded in 2014 associated with the 2007 Rate Case. Other. Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistanceprovided to other utilities through mutual assistance programs, recoveries of environmental costs associated with MGP sites, and recoveries ofenergy procurement costs. 131Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Year EndedDecember 31, Increase(Decrease) Year EndedDecember 31, Increase(Decrease) 2015 2014 2015 vs.2014 2014 2013 2014 vs.2013 Operating and maintenance expense—baseline $1,353 $1,214 $139 $1,214 $1,205 $9 Operating and maintenance expense—regulatory required programs 214 215 (1) 215 163 52 Total operating and maintenance expense $1,567 $1,429 $138 $1,429 $1,368 $61 (a)Operating and maintenance expense 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 year ended December 31, 2015, compared to the same period in 2014, and for theyear ended December 31, 2014, compared to the same period in 2013, consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Baseline Labor, other benefits, contracting and materials $31 $56 Pension and non-pension postretirement benefits expense 19 (85) Storm-related costs 27 (11) Uncollectible accounts expense—provision (7) 12 Uncollectible accounts expense—recovery, net 34 29 Other 35 8 139 9 Regulatory required programs Energy efficiency and demand response programs (1) 52 Increase in operating and maintenance expense $138 $61 (a)Primarily reflects increased contracting costs related to preventative maintenance and other projects for the year ended December 31, 2015, and increased contracting costsresulting from new projects associated with EIMA for the year ended December 31, 2014. See Note 3—Regulatory Matters of the Combined Notes to Consolidated FinancialStatements for additional information regarding EIMA.(b)The increase from 2014 to 2015 primarily reflects the unfavorable impact of lower assumed pension and OPEB discount rates and an increase in the life expectancy assumptionfor plan participants, partially offset by cost savings from plan design changes for certain OPEB plans effective April 2014 and forward. The decrease from 2013 to 2014 primarilyreflects the cost savings from plan design changes for certain OPEB plans effective April 2014 and forward. See Note 16—Retirement Benefits of the Exelon 2014 Form 10-K foradditional 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 2015 and 2014, ComEd recorded a net increase in Operating and maintenance expense related to uncollectible accounts due to the timing ofregulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenue for the periods presented.(d)Primarily reflects increased information technology support services from BSC during 2015. 132(a) (a) (b) (c) (c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDepreciation and Amortization Expense The changes in Depreciation and amortization expense for 2015 compared to 2014, and 2014 compared to 2013, consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Depreciation expense $43 $46 Amortization regulatory assets (28) (21) Other 5 (7) Increase in depreciation and amortization expense $20 $18 (a)Depreciation expense increased due to ongoing capital expenditure during the years ended December 31, 2015 and 2014.(b)For the years ended December 31, 2015 and 2014, primarily relates to a decrease in MGP regulatory asset amortization and ComEd’s severance regulatory assets fully amortizingduring 2014. Taxes Other Than Income Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxesother than income remained relatively consistent for the year ended December 31, 2015, compared to the same period in 2014, and for the yearended December 31, 2014, compared to the same period in 2013. Interest Expense, Net The changes in Interest expense, net, for the year ended 2015 compared to the same period in 2014, and for the year ended 2014 comparedto the same period in 2013, consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Interest expense related to uncertain tax positions $2 $(275) Interest expense on debt (including financing trusts) 13 16 Other (4) 1 Increase (decrease) in interest expense, net $11 $(258) (a)The reduction in interest expense in 2014 from 2013 is primarily attributable to the remeasurement of Exelon’s like-kind exchange tax position recorded in the first quarter of 2013.See Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.(b)Primarily reflects an increase in interest expense due to the issuance of First Mortgage Bonds for the years ended December 31, 2015 and 2014. See Note 14—Debt and CreditAgreements of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s debt obligations. Effective Income Tax Rate ComEd’s effective income tax rates for the years ended December 31, 2015, 2014 and 2013, were 39.7%, 39.6% and 37.9%, respectively.See Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components ofthe effective income tax rates. 133 (a) (b)(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Electric Operating Statistics and Revenue Detail Retail Deliveries to customers (in GWhs) 2015 2014 %Change2015 vs2014 Weather-Normal%Change 2013 %Change2014 vs2013 Weather-Normal%Change Retail Deliveries Residential 26,496 27,230 (2.7)% (1.5)% 27,800 (2.1)% 0.3% Small commercial & industrial 31,717 32,146 (1.3)% (0.9)% 32,305 (0.5)% (0.3)% Large commercial & industrial 27,210 27,847 (2.3)% (2.0)% 27,684 0.6% 0.7% Public authorities & electric railroads 1,309 1,358 (3.6)% (2.6)% 1,355 0.2% (0.7)% Total retail deliveries 86,732 88,581 (2.1)% (1.4)% 89,144 (0.6)% 0.2% As of December 31, Number of Electric Customers 2015 2014 2013 Residential 3,550,239 3,502,386 3,480,398 Small commercial & industrial 370,932 369,053 367,569 Large commercial & industrial 1,976 1,998 1,984 Public authorities & electric railroads 4,820 4,815 4,853 Total 3,927,967 3,878,252 3,854,804 Electric Revenue 2015 2014 %Change2015 vs2014 2013 %Change2014 vs2013 Retail Sales Residential $2,360 $2,074 13.8% $2,073 — % Small commercial & industrial 1,337 1,335 0.1% 1,250 6.8% Large commercial & industrial 443 434 2.1% 427 1.6% Public authorities & electric railroads 42 46 (8.7)% 48 (4.2)% Total retail 4,182 3,889 7.5% 3,798 2.4% Other revenue 723 675 7.1% 666 1.4% Total electric revenue $4,905 $4,564 7.5% $4,464 2.2% (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 revenue also includes rental revenue, revenue related to late payment charges, revenue from other utilitiesfor mutual assistance programs and recoveries of remediation costs associated with MGP sites. 134(a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015 2014 Favorable(unfavorable)2015 vs. 2014variance 2013 Favorable(unfavorable)2014 vs. 2013variance Operating revenue $3,032 $3,094 $(62) $3,100 $(6) Purchased power and fuel 1,190 1,261 71 1,300 39 Revenue net of purchased power and fuel expense 1,842 1,833 9 1,800 33 Other operating expenses Operating and maintenance 794 866 72 748 (118) Depreciation and amortization 260 236 (24) 228 (8) Taxes other than income 160 159 (1) 158 (1) Total other operating expenses 1,214 1,261 47 1,134 (127) Gain on sale of assets 2 — 2 — — Operating income 630 572 58 666 (94) Other income and (deductions) Interest expense, net (114) (113) (1) (115) 2 Other, net 5 7 (2) 6 1 Total other income and (deductions) (109) (106) (3) (109) 3 Income before income taxes 521 466 55 557 (91) Income taxes 143 114 (29) 162 48 Net income 378 352 26 395 (43) Preferred security dividends and redemption — — — 7 7 Net income attributable to common shareholder $378 $352 $26 $388 $(36) (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, 2015 Compared to Year Ended December 31, 2014. PECO’s net income attributable to common shareholder forthe year ended December 31, 2015 was higher than the same period in 2014, primarily due to a decrease in Operating and maintenance expensedue to a decrease in storm costs. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. PECO’s net income attributable to common shareholder forthe year ended December 31, 2014 was lower than the same period in 2013, primarily due to an increase in Operating and maintenance expensedue to an increase in storm costs partially offset by an increase in Operating revenue net of purchase power and fuel expense and a decrease inIncome tax expense. 135(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 natural gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs.PECO’s electric supply and natural gas cost rates charged to customers are subject to adjustments as specified in the PAPUC-approved tariffsthat are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates inaccordance with PECO’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impacton electric and natural gas revenue net of purchased power and fuel expense. Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the CustomerChoice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gassuppliers, respectively. The customer’s choice of suppliers does not impact the volume of deliveries, but affects revenue collected fromcustomers related to supplied energy and natural gas service. Customer Choice Program activity has no impact on electric and natural gasrevenue net of purchase power and fuel expense. Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales,respectively) for the years ended December 31, 2015, 2014, and 2013 consisted of the following: For the Years Ended December 31, 2015 2014 2013 Electric 70% 70% 68% Natural Gas 25% 22% 19% Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers atDecember 31, 2015, 2014, and 2013 consisted of the following: December 31, 2015 December 31, 2014 December 31, 2013 Number ofcustomers % of totalretailcustomers Number ofcustomers % of totalretailcustomers Number ofcustomers % of totalretailcustomers Electric 563,400 35% 546,900 34% 531,500 34% Natural Gas 81,100 16% 78,400 16% 66,400 13% The changes in PECO’s Operating revenue net of purchased power and fuel expense for the years ended December 31, 2015 andDecember 31, 2014 compared to the same periods in 2014 and 2013, respectively, consisted of the following: 2015 vs. 2014 2014 vs. 2013 Increase (Decrease) Increase (Decrease) Electric Gas Total Electric Gas Total Weather $28 $(19) $9 $(15) $13 $(2) Volume 4 7 11 2 5 7 Pricing 4 2 6 (1) (3) (4) Regulatory required programs (6) — (6) 33 — 33 Other (12) 1 (11) (1) — (1) Total increase (decrease) $18 $(9) $9 $18 $15 $33 Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warmweather in summer months and, with respect to the electric 136Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditionsresult in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. Operating revenue net of purchased powerand fuel expense for the year ended December 31, 2015 was higher primarily due to the impact of favorable 2015 summer and first quarter winterweather conditions, partially offset by the impact of unfavorable fourth quarter 2015 winter weather conditions in PECO’s service territory. Operating revenue net of purchased power and fuel expense for the year ended December 31, 2014, was lower due to the impact ofunfavorable 2014 summer and fourth quarter weather conditions, partially offset by the impact of favorable first quarter 2014 winter weatherconditions in PECO’s service territory. Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business.Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. Thechanges in heating and cooling degree days in PECO’s service territory for the years ended December 31, 2015 and December 31, 2014 comparedto the same periods in 2014 and 2013, respectively, and normal weather consisted of the following: For the Years EndedDecember 31, % Change Heating and Cooling Degree-Days 2015 2014 Normal 2015 vs. 2014 2015 vs. Normal Heating Degree-Days 4,245 4,749 4,613 (10.6)% (8.0)% Cooling Degree-Days 1,720 1,311 1,301 31.2% 32.2% For the Years EndedDecember 31, % Change Heating and Cooling Degree-Days 2014 2013 Normal 2014 vs. 2013 2014 vs. 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 ofweather, for the year ended December 31, 2015, primarily reflects the impact of moderate economic and customer growth partially offset by energyefficiency initiatives on customer usages for gas and residential and small commercial and industrial electric classes. Additionally, the increaserepresents a shift in the volume profile across classes from large commercial and industrial classes to residential and small commercial andindustrial classes for electric. The increase in Operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather,for the year ended December 31, 2014, primarily reflects the impact of moderate economic and customer growth partially offset by energyefficiency initiatives on customer usages for gas and residential electric and a shift in the volume profile across classes from commercial andindustrial classes to residential classes for electric. Pricing. The increase in electric operating revenue net of purchased power expense as a result of pricing for the year ended December 31,2015 is primarily attributable to increased monthly customer demand in the commercial and industrial classes. The increase in natural gasoperating revenue net of fuel expense as a result of pricing for the year ended December 31, 2015, is primarily attributable to higher overalleffective rates due to decreased retail gas usage. The decrease in natural gas operating revenue net of fuel expense as a result of pricing for the year ended December 31, 2014, is primarilyattributable to lower overall effective rates due to increased retail gas usage. 137Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsRegulatory Required Programs. This represents the change in operating revenue collected under approved riders to recover costs incurred forregulatory programs such as smart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as wellas a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Incometaxes. Refer to the Operating and maintenance expense discussion below for additional information on included programs. Other. The decrease in other electric revenue net of purchased power expense for the year ended December 31, 2015 reflects the impact oflower wholesale transmission revenue, which is impacted by the previous year’s peak demand, which was lower in 2014 than in 2013. Operating and Maintenance Expense Year EndedDecember 31, Increase(Decrease) Year EndedDecember 31, Increase(Decrease) 2015 2014 2015 vs. 2014 2014 2013 2014 vs. 2013 Operating and maintenance expense—baseline $685 $761 $(76) $761 $668 $93 Operating and maintenance expense—regulatory required programs 109 105 $4 105 80 $25 Total operating and maintenance expense $794 $866 $(72) $866 $748 $118 (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 2015 compared to 2014 and 2014 compared to 2013 consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Baseline Labor, other benefits, contracting and materials $1 $12 Storm-related costs (78) 100 Pension and non-pension postretirement benefits expense 3 (5) Merger integration costs 2 (7) Corporate allocation 9 5 Uncollectible accounts expense (22) (9) Other 9 (3) (76) 93 Regulatory required programs Smart meter (3) 7 Energy efficiency 8 17 Other (1) 1 4 25 Increase (decrease) in operating and maintenance expense $(72) $118 138(a)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)Reflects a reduction of $67 million in incremental storm costs, primarily as a result of the February 5, 2014 ice storm.(b)Reflects an increase of $85 million in incremental storm costs, including the February 5, 2014 ice storm and the significant July 2014 storms. Depreciation and Amortization Expense The changes in Depreciation and amortization expense for 2015 compared to 2014 and 2014 compared to 2013, consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Depreciation expense $13 $8 Regulatory asset amortization 11 — Increase in depreciation and amortization expense $24 $8 Taxes Other Than Income Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxesother than income remained relatively consistent for the year ended December 31, 2015, compared to the same period in 2014, and the year endedDecember 31, 2014, compared to the same period in 2013. Interest Expense, Net Interest expense, net remained relatively consistent for the year ended December 31, 2015, compared to the same period in 2014, and theyear ended December 31, 2014, compared to the same period in 2013. Other, Net Other, net remained relatively consistent for the year ended December 31, 2015, compared to the same period in 2014, and the year endedDecember 31, 2014, compared to the same period in 2013. Effective Income Tax Rate PECO’s effective income tax rates for the years ended December 31, 2015, 2014 and 2013 were 27.4%, 24.5% and 29.1%, 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) 2015 2014 %Change2015 vs.2014 Weather-Normal%Change 2013 %Change2014 vs.2013 Weather-Normal%Change Retail Deliveries Residential 13,630 13,222 3.1% 0.3% 13,341 (0.9)% 0.5% Small commercial & industrial 8,118 8,025 1.2% 0.6% 8,101 (0.9)% — % Large commercial & industrial 15,365 15,310 0.4% (0.5)% 15,379 (0.4)% (0.1)% Public authorities & electric railroads 881 937 (6.0)% (6.0)% 930 0.8% 0.8% Total electric retail deliveries 37,994 37,494 1.3% (0.1)% 37,751 (0.7)% 0.1% 139(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 As of December 31, Number of Electric Customers 2015 2014 2013 Residential 1,444,338 1,434,011 1,423,068 Small commercial & industrial 149,200 149,149 149,117 Large commercial & industrial 3,091 3,103 3,105 Public authorities & electric railroads 9,805 9,734 9,668 Total 1,606,434 1,595,997 1,584,958 Electric Revenue 2015 2014 %Change2015 vs.2014 2013 %Change2014 vs.2013 Retail Sales Residential $1,599 $1,555 2.8% $1,592 (2.3)% Small commercial & industrial 428 423 1.2% 433 (2.3)% Large commercial & industrial 221 217 1.8% 224 (3.1)% Public authorities & electric railroads 31 32 (3.1)% 30 6.7% Total retail 2,279 2,227 2.3% 2,279 (2.3)% Other revenue 207 221 (6.3)% 221 — % Total electric operating revenue $2,486 $2,448 1.6% $2,500 (2.1)% (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 reflects 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) 2015 2014 %Change2015 vs.2014 Weather-Normal%Change 2013 %Change2014 vs.2013 Weather-Normal%Change Retail Deliveries Retail sales 59,003 62,734 (5.9)% 3.3% 57,613 8.9% 2.2% Transportation and other 27,879 27,208 2.5% 1.2% 28,089 (3.1)% (1.0)% Total natural gas deliveries 86,882 89,942 (3.4)% 2.6% 85,702 4.9% 1.2% As of December 31, Number of Gas Customers 2015 2014 2013 Residential 467,263 462,663 458,356 Commercial & industrial 43,160 42,686 42,174 Total retail 510,423 505,349 500,530 Transportation 827 855 909 Total 511,250 506,204 501,439 Gas revenue 2015 2014 %Change2015 vs.2014 2013 %Change2014 vs.2013 Retail Sales Retail sales $511 $608 (16.0)% $562 8.2% Transportation and other 35 38 (7.9)% 38 — % Total natural gas operating revenue $546 $646 (15.5)% $600 7.7% 140(a) (b)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)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 reflects the cost of natural gas. Results of Operations—BGE 2015 2014 Favorable(unfavorable)2015 vs. 2014variance 2013 Favorable(unfavorable)2014 vs. 2013variance Operating revenue $3,135 $3,165 $(30) $3,065 $100 Purchased power and fuel expense 1,305 1,417 112 1,421 4 Revenue net of purchased power and fuel expense 1,830 1,748 82 1,644 104 Other operating expenses Operating and maintenance 683 717 34 634 (83) Depreciation and amortization 366 371 5 348 (23) Taxes other than income 224 221 (3) 213 (8) Total other operating expenses 1,273 1,309 36 1,195 (114) Gain on sales of assets 1 — 1 — — Operating income 558 439 119 449 (10) Other income and (deductions) Interest expense, net (99) (106) 7 (122) 16 Other, net 18 18 — 17 1 Total other income and (deductions) (81) (88) 7 (105) 17 Income before income taxes 477 351 126 344 7 Income taxes 189 140 (49) 134 (6) Net income 288 211 77 210 1 Preference stock dividends 13 13 — 13 — Net income attributable to common shareholder $275 $198 $77 $197 $1 (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 Attributable to Common Shareholder Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Net income attributable to common shareholder was higherprimarily due to an increase in Revenue net of purchased power and fuel expense as a result of the December 2014 electric and gas distributionrate order issued by the MDPSC, an increase in transmission formula rate revenues and a reduction in Operating and maintenance expense as aresult of a decrease in bad debt expense and storm costs in the BGE service territory. 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 141(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsRevenue net of purchased power and fuel expense as a result of the December 2013 and 2014 electric and gas distribution rate orders issued bythe MDPSC offset by increases in Operating and maintenance expense and Depreciation expense. Operating Revenue Net of Purchased Power and Fuel Expense There are certain drivers to Operating revenue that are offset by their impact on Purchased power and fuel expense, such as commodityprocurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Electric and gas revenue andPurchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged tocustomers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electricpower and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodityprograms, respectively. BGE is obligated to provide market-based SOS to all of its electric customers. The SOS rates charged recover BGE’s wholesale powersupply costs and include an administrative fee. The administrative fee includes a shareholder return component, which for residential SOScustomers is being returned to residential distribution customers through December 31, 2016, and an incremental cost component. Bidding tosupply BGE’s market-based SOS occurs through a competitive bidding process approved by the MDPSC. Successful bidders, which may includeGeneration, will execute contracts with BGE for terms of three months or two years. BGE is obligated by the MDPSC to provide several variationsof SOS to commercial and industrial customers depending on customer load. Charges incurred for electric supply procured through contracts withGeneration are included in Purchased power from affiliates on BGE’s Statement of Operations and Comprehensive Income. 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 and/or natural gasfrom a competitive natural gas supplier. This customer choice of electric generation suppliers does not impact the volume of deliveries, but affectsrevenue collected from customers related to SOS. Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales,respectively) at December 31, 2015, 2014 and 2013 consisted of the following: For the Years Ended December 31, 2015 2014 2013 Electric 61% 60% 61% Natural Gas 56% 53% 54% Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers atDecember 31, 2015, 2014 and 2013 consisted of the following: December 31, 2015 December 31, 2014 December 31, 2013 Number ofCustomers % of total retailcustomers Number ofCustomers % of total retailcustomers Number ofCustomers % of total retailcustomers Electric 343,000 27% 364,000 29% 399,000 32% Natural Gas 154,000 23% 161,000 25% 172,000 26% 142Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Operating revenue net of purchased power and fuel expense for the year ended December 31, 2015 compared to thesame period in 2014 and for the year ended December 31, 2014 compared to the same period in 2013, respectively, consisted of the following: 2015 2014 Increase (Decrease) Increase (Decrease) Electric Gas Total Electric Gas Total Distribution rate increase $20 $35 $55 $57 $28 $85 Regulatory required programs 4 2 6 13 (1) 12 Transmission revenue 11 — 11 10 — 10 Other 10 — 10 (13) 10 (3) Total increase $45 $37 $82 $67 $37 $104 Revenue Decoupling. The demand for electricity and gas is affected by weather and usage conditions. The MDPSC has allowed BGE torecord a monthly adjustment to its electric and gas distribution revenue from all residential customers, commercial electric customers, the majorityof large industrial electric customers, and all firm service 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 revenue per customer, bycustomer class, regardless of changes in consumption levels. This allows BGE to recognize revenue at MDPSC-approved levels per customer,regardless of what BGE’s actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth, it willnot be affected by actual weather or usage conditions. BGE bills or credits impacted customers in subsequent months for the difference betweenapproved revenue levels under revenue decoupling and actual customer billings. Heating 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 and cooling degree days in BGE’s service territory for the year ended December 31, 2015 compared to the same period in 2014 and for theyear ended December 31, 2014 compared to the same period in 2013, respectively, and normal weather consisted of the following: For the Year EndedDecember 31, Normal % Change Heating and Cooling Degree-Days 2015 2014 2015 vs. 2014 From Normal Heating Degree-Days 4,666 5,091 4,663 (8.3)% 0.1% Cooling Degree-Days 924 732 875 26.2% 5.6% For the Year EndedDecember 31, Normal % Change Heating and Cooling Degree-Days 2014 2013 2014 vs. 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 Increase. The increase in distribution revenue for the year ended December 31, 2015 was primarily due to the impact of thenew electric and natural gas distribution rates charged to customers that became effective in December 2014 in accordance with the MDPSCapproved electric and natural gas distribution rate case order. The increase in distribution revenue for the year ended December 31, 2014 was primarily due to the impact of new electric and natural gasdistribution rates charged to customers that became 143Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 in December 2013 and 2014, in accordance with the MDPSC approved electric and natural gas distribution rate case orders. See Note 3—Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for further information. Regulatory Required Programs. This represents the change in revenue collected under approved riders to recover costs incurred for theenergy efficiency and demand response programs as well as administrative and commercial and industrial customer bad debt costs for SOS. Theriders are designed to provide full recovery, as well as a return in certain instances. The costs of these programs are included in Operating andmaintenance expense, Depreciation and amortization expense and Taxes other than income in BGE’s Consolidated Statements of Operations andComprehensive Income. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in theunderlying costs, investments being recovered and other billing determinants. During the years ended December 31, 2015 and 2014, the increasein transmission revenue was primarily due to higher Operating and maintenance expense and increased capital investment. See Operating andMaintenance Expense below and Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additionalinformation. Other. Other revenue, which can vary from period to period, includes miscellaneous revenue such as service application and late paymentfees. Operating and Maintenance Expense The changes in operating and maintenance expense for 2015 compared to 2014 and 2014 compared to 2013 consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Baseline Labor, other benefits, contracting and materials $12 $22 Pension and non-pension postretirement benefits expense (1) 8 Storm-related costs (21) 21 Uncollectible accounts expense (49) 17 Merger integration costs 3 5 Other 22 10 (Decrease) increase in operating and maintenance expense $(34) $83 (a)Storm-related costs decreased due to lack of major storms for the year ended December 31, 2015 compared to the same period in 2014.(b)Uncollectible accounts expense decreased primarily due to improved customer behavior and favorable weather for the year ended December 31, 2015 compared to the sameperiod in 2014. Conduit Lease with City of Baltimore On September 23, 2015, the Baltimore City Board of Estimates approved an increase in rental fees for access to the Baltimore City conduitsystem effective November 1, 2015, which is expected to result in an increase to operating and maintenance expense of approximately $24 millionin 2016 subject to an annual increase based on the Consumer Price Index. On October 16, 2015, BGE filed a lawsuit against the City in the CircuitCourt for Baltimore City to protect its customers from any improper use by the City of the conduit fee revenues and to place constraints on theCity’s ability to set the conduit fee in the future. 144(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsAmong the relief sought by BGE was a preliminary injunction preventing the City from enforcing its substantial increase in the conduit feerate during the course of the litigation. A hearing was held in the Circuit Court for Baltimore County on December 15, 2015. While BGE’s motion forpreliminary injunction was denied, the Court’s decision was premised upon several important concessions or acknowledgments made by the Cityin its written papers and at the hearing. Most importantly, the City conceded that it can charge BGE only for the actual costs of conduitmaintenance and that a true-up process is required to the extent that the City fails to spend the amount collected for conduit maintenance. As part of its electric and gas distribution rate case filed on November 6, 2015, and as amended on January 5, 2016, BGE is proposing torecover the annual increase in conduit fees, effective November 1, 2015 of approximately $30 million through a surcharge. BGE cannot predict ifthe MDPSC will approve BGE’s request for a conduit fee surcharge. Depreciation and Amortization Expense The changes in depreciation and amortization expense for 2015 compared to 2014 and 2014 compared to 2013 consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Depreciation expense $2 $25 Regulatory asset amortization (6) (1) Other (1) (1) (Decrease) increase in depreciation and amortization expense $(5) $23 (a)Depreciation expense increased due to ongoing capital expenditures during the year ended December 31, 2015 compared to 2014 and 2014 compared 2013. The increase forthe year ended December 31, 2015 compared to 2014 was offset by the effect of revised depreciation rates established in accordance with the MDPSC approved December 2014electric and natural gas distribution rate case order.(b)Regulatory asset amortization decreased for the year ended December 31, 2015 compared to the same period in 2014 due to a reduction in regulatory asset amortization relatedto demand response programs and revised recovery periods for certain regulatory assets in accordance with the MDPSC approved December 2014 electric and natural gasdistribution rate case order. Taxes Other Than Income The change in taxes other than income for 2015 compared to 2014 and 2014 compared to 2013 consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Property tax $3 $2 Franchise tax 1 4 Other (1) 2 Increase in taxes other than income $3 $8 145(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 The decrease in Interest expense, net for 2015 compared to 2014 and 2014 compared to 2013 consisted of the following: Increase(Decrease)2015 vs. 2014 Increase(Decrease)2014 vs. 2013 Interest expense on debt (including financing trusts) $(4) $(10) Interest expense related to capitalization of interest / AFUDC (2) (6) Interest expense related to uncertain tax positions (1) — Decrease in interest expense, net $(7) $(16) Effective Income Tax Rate BGE’s effective income tax rates for the years ended December 31, 2015, 2014 and 2013 were 39.6%, 39.9% and 39.0%, respectively. SeeNote 15—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) 2015 2014 % Change2015 vs. 2014 Weather-Normal %Change 2013 % Change2014 vs. 2013 Weather-Normal %Change Retail Deliveries Residential 12,598 12,974 (2.9)% n.m. 13,077 (0.8)% n.m. Small commercial & industrial 3,119 3,086 1.1% n.m. 3,035 1.7% n.m. Large commercial & industrial 14,293 14,191 0.7% n.m. 14,339 (1.0)% n.m. Public authorities & electric railroads 294 311 (5.5)% n.m. 317 (1.9)% n.m. Total electric deliveries 30,304 30,562 (0.8)% n.m. 30,768 (0.7)% n.m. As of December 31, Number of Electric Customers 2015 2014 2013 Residential 1,137,934 1,125,369 1,120,431 Small commercial & industrial 113,138 112,972 112,850 Large commercial & industrial 11,906 11,730 11,652 Public authorities & electric railroads 285 290 292 Total 1,263,263 1,250,361 1,245,225 146(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015 2014 % Change2015 vs. 2014 2013 % Change2014 vs. 2013 Retail Sales Residential $1,449 $1,404 3.2% $1,404 — % Small commercial & industrial 273 271 0.7% 257 5.4% Large commercial & industrial 469 491 (4.5)% 439 11.8% Public authorities & electric railroads 32 32 — % 31 3.2% Total retail 2,223 2,198 1.1% 2,131 3.1% Other revenue 267 262 1.9% 274 (4.4)% Total electric operating revenue $2,490 $2,460 1.2% $2,405 2.3% (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. BGE Gas Operating Statistics and Revenue Detail Deliveries to customers (in mmcf) 2015 2014 % Change2015 vs. 2014 Weather-Normal %Change 2013 % Change2014 vs. 2013 Weather-Normal %Change Retail Deliveries Retail sales 96,618 99,194 (2.6)% n.m. 94,020 5.5% n.m. Transportation and other 6,238 9,242 (32.5)% n.m. 12,210 (24.3)% n.m. Total natural gas deliveries 102,856 108,436 (5.1)% n.m. 106,230 2.1% n.m. As of December 31, Number of Gas Customers 2015 2014 2013 Residential 616,994 609,626 611,532 Commercial & industrial 44,119 44,200 44,162 Total 661,113 653,826 655,694 Gas revenue 2015 2014 % Change2015 vs. 2014 2013 % Change2014 vs. 2013 Retail Sales Retail sales $607 $622 (2.4)% $592 5.1% Transportation and other 38 83 (54.2)% 68 22.1% Total natural gas operating revenue $645 $705 (8.5)% $660 6.8% (a)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.(b)Transportation and other gas revenue includes off-system revenue of 6,238 mmcfs ($35 million), 9,242 mmcfs ($72 million), and 12,210 mmcfs ($55 million) for the years ended2015, 2014 and 2013, respectively.(c)Other revenue includes operating revenue with affiliates. 147(a) (a) (b)(c)(a) (b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsLiquidity and Capital Resources Exelon’s and Generation’s prior year activity presented below includes the activity of CENG, from the integration date effective April 1, 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. Exelon Corporate, Generation, ComEd, PECO and BGE’s syndicated revolving credit facilities expire in 2018 and 2019. In addition,Generation has $0.4 billion in bilateral facilities with banks which have various expirations between March 2016 and January 2019. The Registrantsutilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. Seethe “Credit Matters” section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financingcosts and capital expenditure requirements. The 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 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussion of theRegistrants’ debt and credit agreements. PHI Merger Financing Exelon has raised cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments, through theissuance of $4.2 billion of debt (of which $3.3 billion remains after execution of the exchange offer, see Note 14—Debt and Credit Agreements forfurther information on the exchange), $1.15 billion of junior subordinated notes in the form of 23 million equity units, the issuance of $1.9 billion ofcommon stock, cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion) and theremaining balance from cash on hand and/or short-term borrowings available to Exelon. Exelon will have sufficient cash to fund the all-cashpurchase price, acquisition and integration related costs, and merger commitments. See Note 14—Debt and Credit Agreements and Note 19—Shareholder’s Equity for further information on the debt and equity issuances. In the event the PHI merger is terminated, the Board of Directorscould direct Exelon to use its existing cash on hand to retire debt, to return capital to shareholders or for other general corporate purposes. 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 148Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsactivities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitivecosts 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 23—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. On November 2, 2015 the funding relief wasextended for an additional three years and premiums pension plans pay to the Pension Benefit Guaranty Corporation were further increased. Theestimated impacts of the law are reflected in the projected pension contributions below. Exelon expects to make qualified pension plan contributions of $250 million to its qualified pension plans in 2016, of which Generation,ComEd, PECO and BGE expect to contribute $134 million, $30 million, $28 million and $31 million, respectively. Exelon’s and Generation’sexpected qualified pension plan contributions above include $25 million related to the legacy CENG plans that will be funded by CENG as providedin an Employee Matters Agreement (EMA) between Exelon and CENG. Exelon’s non-qualified pension plans are not funded. Exelon expects tomake non-qualified pension plan benefit payments of $21 million in 2016, of which Generation, ComEd, PECO and BGE will make payments of $9million, $2 million, $1 million and $1 million respectively. See Note 17—Retirement Benefits of the Combined Notes to Consolidated FinancialStatements for the Registrants’ 2015 and 2014 pension contributions. To 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. Additionally, the contributions above could change if Exelon changes its pension funding strategy. Unlike qualified pension plans, other postretirement benefit plans are not subject to statutory minimum contribution requirements and 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 $35 million in 2016, of which Generation, ComEd, PECO, and BGE 149Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsexpect to contribute $13 million, $3 million, $1 million, and $18 million, respectively. See Note 17— Retirement Benefits of the Combined Notes toConsolidated Financial Statements for the Registrants’ 2015 and 2014 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, Exelon would be required to either post a bondor pay the tax and interest for the tax years before the court to appeal the decision. If an adverse decision is reached in 2016, thepotential tax and after-tax interest, exclusive of penalties, that could become payable may be as much as $860 million, of whichapproximately $300 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless from anyunfavorable impacts of the after-tax interest amounts on ComEd’s equity, and the balance at Exelon. It is expected that Exelon’sremaining tax years affected by the litigation will be settled following a final appellate decision which could take several years. • Exelon, Generation, and ComEd expect to receive tax refunds of approximately $430 million, $190 million, and $260 million,respectively, in 2016. PECO expects to make tax payments of approximately $7 million related to IRS positions settling in 2016. • State and local governments continue to face increasing financial challenges, which may increase the risk of additional income taxlevies, property taxes and other taxes or the imposition, extension or permanence of temporary tax levies. • On December 18, 2015, President Obama signed H.R. 2029, the Protecting Americans from Tax Hikes (PATH) Act. The Act included anextension of 50% bonus depreciation for 2015—2017. It also includes provisions for 40% and 30% bonus depreciation allowance forqualified property placed in service in 2018 and 2019, respectively. As a result of the 50% bonus depreciation extension for 2015,Exelon, Generation, ComEd, PECO, and BGE are estimated to generate incremental cash in 2016 of approximately $690 million, $350million, $220 million, $70 million, and $50 million, respectively. Furthermore, the extension of 50% bonus depreciation resulted in adecrease to Generation’s Domestic Production Activities Deduction, reducing cash tax benefits and increasing income tax expense byapproximately $65 million in 2015. Due to the extension of bonus depreciation, ComEd’s 2015 revenue requirement decreased byapproximately $10 million (after-tax). 150Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 31,2015, 2014 and 2013: 2015 2014 2015 vs. 2014Variance 2013 2014 vs. 2013Variance Net income $2,250 $1,820 $430 1,729 $91 Add (subtract): Non-cash operating activities 5,630 5,884 (254) 4,159 1,725 Pension and non-pension postretirement benefit contributions (502) (617) 115 (422) (195) Income taxes 97 (143) 240 883 (1,026) Changes in working capital and other noncurrent assets andliabilities (264) (806) 542 (185) (621) Option premiums received (paid), net 58 38 20 (36) 74 Collateral received (posted), net 347 (1,719) 2,066 215 (1,934) Net cash flows provided by operations $7,616 $4,457 $3,159 $6,343 $(1,886) (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 24 —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)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 and 2014 activity includes CENG on a fully consolidated basis beginningApril 1, 2014. Cash flows provided by operations for the year ended December 31, 2015, 2014 and 2013 by Registrant were as follows: 2015 2014 2013 Exelon $7,616 $4,457 $6,343 Generation 4,199 1,826 3,887 ComEd 1,896 1,326 1,218 PECO 770 712 747 BGE 782 740 561 (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 and 2014 activity includes CENG on a fully consolidated basis beginningApril 1, 2014. Changes 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 2015, 2014 and 2013 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 an exchange or in the OTC markets. During 2015, 2014 and 2013, Generation had net collections/(payments) ofcounterparty cash collateral of $407 million, $(1,748) million and $162 million, respectively, primarily due to market conditions thatresulted in changes to 151(c)(a)(b)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Generation’s net mark-to-market position, as well as Exelon’s decision to post more cash collateral in 2014 compared to using letters ofcredit in 2015 to support the PHI merger financing. • During 2015, 2014 and 2013, Generation had net collections/(payments) of approximately $58 million, $38 million and $(36) million,respectively, related to purchases and sales of options. The level of option activity in a given year may vary due to several factors,including changes in market conditions as well as changes in hedging strategy. ComEd • During 2015, 2014 and 2013, ComEd’s payables for Generation energy purchases increased/(decreased) by $(28) million, $5 million and$(16) million, respectively, and payables to other energy suppliers for energy purchases increased by $2 million, $27 million and $35million, respectively. • During 2015, ComEd posted $31 million of cash collateral to PJM. During 2014, ComEd posted no cash collateral to PJM. ComEd’scollateral posted with PJM has increased year over year primarily due to higher RPM credit requirements and higher PJM billingsresulting from increased load being served by ComEd as a result of City of Chicago customers switching back to ComEd. PECO • During 2015, 2014 and 2013, PECO’s payables to Generation for energy purchases increased/(decreased) by $7 million, $(9) million and$(17) million, respectively, and payables to other energy suppliers for energy purchases increased/(decreased) by $(38) million, $10million and $39 million, respectively. BGE • During 2015, 2014 and 2013, BGE’s payables to Generation for energy purchases increased/(decreased) by $(9) million, $13 million and$(4) million, respectively, and payables to other energy suppliers for energy purchases decreased by $(25) million, $(7) million and $(12)million, respectively. Cash Flows from Investing Activities Cash flows used in investing activities for the year ended December 31, 2015, 2014, and 2013 by Registrant were as follows: 2015 2014 2013 Exelon $(7,822) $(4,599) $(5,394) Generation (4,069) (1,767) (2,916) ComEd (2,362) (1,655) (1,387) PECO (588) (649) (531) BGE (675) (622) (571) (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 and 2014 activity includes CENG on a fully consolidated basis beginningApril 1, 2014. 152(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Generation has entered into several agreements to acquire equity interests in privately held development stage entities which developenergy-related technology. The agreements contain a series of scheduled investment commitments, including in-kind services contributions. Thereare approximately $327 million of anticipated expenditures remaining through 2018 to fund anticipated planned capital and operating needs of theassociated companies, of which up to $172 million will be contributed by a non-controlling interest holder. See Note 23—Commitments andContingencies of the Combined Notes to Consolidated Financial Statements for further details of Generation’s equity interests. Capital expenditures by Registrant for the year ended December 31, 2015, 2014, and 2013 and projected amounts for 2016 are as follows: Projected2016 2015 2014 2013 Exelon $7,600 $7,624 $6,077 $5,395 Generation 3,600 3,841 3,012 2,752 ComEd 2,425 2,398 1,689 1,433 PECO 675 601 661 537 BGE 825 719 620 587 Other 75 65 95 86 (a)Total projected capital expenditures do not include adjustments for non-cash activity.(b)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 and 2014 activity includes CENG on a fully consolidated basis beginningApril 1, 2014.(c)The capital expenditures and 2016 projections include $610 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billionover a ten year period to modernize and storm-harden its distribution system and to implement smart grid technology.(d)Other primarily consists of corporate operations and BSC.(e)Generation’s capital expenditures for the projected full year 2016 includes nuclear fuel of $1.1 billion and growth expenditures of $1.4 billion. 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 through 2016 associated with the CIP V.5 complianceimplementation project, which are included in projected capital expenditures above. Generation Approximately 32% and 15% of the projected 2016 capital expenditures at Generation are for the acquisition of nuclear fuel and theconstruction of new natural gas plants, respectively, with the remaining amounts reflecting investment in renewable energy and additions andupgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they willfund capital expenditures with internally generated funds and borrowings. 153(a)(b)(b)(e)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 86%, 98% and 97% of the projected 2016 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. In addition to the capital expenditure for continuing projects, ComEd’s total expenditures include smart grid/smart meter technologyrequired under EIMA and for PECO and BGE, total capital expenditures related to their respective smart meter program. 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 have been 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 forecasted2016 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 a combination of internally generated funds and borrowingsand additional capital contributions from parent, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 3—Regulatory Matters 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, 2015, 2014, and 2013 by Registrant were as follows: 2015 2014 2013 Exelon $4,830 $411 $(826) Generation (479) (537) (384) ComEd 467 359 61 PECO 83 (250) (361) BGE (162) (85) (48) (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. 154 (a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsDebt. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of theRegistrants’ debt issuances and retirements. Debt activity for 2015, 2014 and 2013 by Registrant was as follows: During the year ended December 31, 2015, the following long term debt was issued: Company Type InterestRate Maturity Amount Use of ProceedsExelonCorporate Senior Unsecured Notes 1.55% June 9, 2017 $550 Finance a portion of the pendingmerger with PHI and related costsand expenses, and for generalcorporate purposesExelonCorporate Senior Unsecured Notes 2.85% June 15, 2020 900 Finance a portion of the pendingmerger with PHI and related costsand expenses, and for generalcorporate purposesExelonCorporate Senior Unsecured Notes 3.95% June 15, 2025 1,250 Finance a portion of the pendingmerger with PHI and related costsand expenses, and for generalcorporate purposesExelonCorporate Senior Unsecured Notes 4.95% June 15, 2035 500 Finance a portion of the pendingmerger with PHI and related costsand expenses, and for generalcorporate purposesExelonCorporate Senior Unsecured Notes 5.10% June 15, 2045 1,000 Finance a portion of the pendingmerger with PHI and related costsand expenses, and for generalcorporate purposesExelonCorporate Long Term Software LicenseAgreement 3.95% May 1, 2024 111 Procurement of software licensesGeneration Senior Unsecured Notes 2.95% January 15,2020 750 Fund the optional redemption ofExelon’s $550 million, 4.550%Senior Notes and for generalcorporate purposes 155(a)(a)(a)(b)(a)(b) (a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsCompany Type Interest Rate Maturity Amount Use of ProceedsGeneration AVSR DOE Nonrecourse Debt 2.29 - 2.96% January 5,2037 39 Antelope Valley solar developmentGeneration Energy Efficiency Project Financing 3.71% July 31, 2017 42 Funding to install energyconservation measures in Coleman,FloridaGeneration Energy Efficiency Project Financing 3.55% November 15,2016 19 Funding to install energyconservation measures in Frederick,MarylandGeneration Tax Exempt Pollution Control RevenueBonds 2.50 - 2.70% 2019 - 2020 435 General corporate purposesGeneration Albany Green Energy Project Financing LIBOR +1.25% November 17,2017 100 Albany Green Energy biomassgeneration developmentGeneration Nuclear Fuel Procurement Contract 3.15% September 30,2020 57 Procurement of nuclear fuelComEd First Mortgage Bonds, Series 118 3.70% March 1,2045 400 Refinance maturing mortgagebonds, repay a portion of ComEd’soutstanding commercial paperobligations and for general corporatepurposesComEd First Mortgage Bonds, Series 119 4.35% November 15,2045 450 Repay a portion of ComEd’soutstanding commercial paperobligations and for general corporatepurposes.PECO First and Refunding Mortgage Bonds 3.15% October 15,2025 350 General corporate purposes (a)See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of the merger financing.(b)In connection with the issuance of PHI merger financing, Exelon terminated its floating-to-fixed interest rate swaps that had been designated as cash flow hedges. See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for further information.(c)In connection with the issuance of Senior Unsecured Notes, Exelon terminated floating-to-fixed interest rate swaps that had been designated as cash flow hedges. See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for further information on the swap termination.(d)See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.(e)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.(f)The Tax Exempt pollution Control Revenue Bonds have a mandatory put date that ranges from March 1, 2019—September 1, 2020. 156(d)(e)(e)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 InterestRate Maturity Amount Use of ProceedsExelonCorporate Junior Subordinated Notes 2.50% June 1, 2024 $1,150 Finance a portion of the pendingmerger with PHI and for generalcorporate purposesGeneration Nuclear Fuel Purchase Contract 3.25 - 3.35% June 30, 2018 70 Procurement of uraniumGeneration ExGen Renewables I NonrecourseDebt LIBOR +4.25% February 6, 2021 300 General corporate purposesGeneration ExGen Texas Power NonrecourseDebt LIBOR +4.75% September 18, 2021 675 General corporate purposesGeneration Energy Efficiency ProjectFinancing 4.12% December 31, 2015 12 Funding to install energyconservation measures inWashington, DCGeneration AVSR DOE Nonrecourse Debt 3.06 - 3.14% January 5, 2037 126 Antelope Valley solardevelopmentComEd First Mortgage Bonds, Series 115 2.15% January 15, 2019 300 Refinance maturing mortgagebonds and general corporatepurposesComEd First Mortgage Bonds, Series 116 4.70% January 15, 2044 350 Refinance maturing mortgagebonds and general corporatepurposesComEd First Mortgage Bonds, Series 117 3.10% November 1, 2024 250 Repay commercial paperobligations and general corporatepurposesPECO First and Refunding MortgageBonds 4.15% October 1, 2044 300 Refinance existing mortgagebonds and general corporatepurposes 157Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 InterestRate Maturity Amount Use of ProceedsGeneration CEU Upstream Nonrecourse Debt 2.21 - 2.44% July 22, 2016 $5 Fund Upstream gas activitiesGeneration AVSR DOE Nonrecourse Debt 2.53 - 3.35% January 5, 2037 227 Antelope Valley solardevelopmentGeneration Social Security AdministrationProject Financing 2.93% February 18, 2015 1 Funding to install conservationmeasures for the SocialSecurity AdministrationHeadquarters facility inMarylandGeneration Energy Efficiency ProjectFinancing 4.40% August 31, 2014 9 Funding to install energyconservation measures inBeckley, West VirginiaGeneration Continental Wind NonrecourseDebt 6.00% February 28, 2033 613 General corporate purposesComEd First Mortgage Bonds, Series 114 4.60% August 15, 2043 350 Repay commercial paperobligations and for generalcorporate purposesPECO First and Refunding MortgageBonds 1.20% October 15, 2016 300 Pay at maturity first andrefunding mortgage bonds dueOctober 15, 2013 and othergeneral corporate purposesPECO First and Refunding MortgageBonds 4.80% October 15, 2043 250 Pay at maturity first andrefunding mortgage bonds dueOctober 15, 2013 and othergeneral corporate purposesBGE Notes 3.35% July 1, 2023 300 Partially refinance Notes dueJuly 1, 2013 and for generalcorporate purposes 158Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015, the following long term debt was retired and/or redeemed: Company Type Interest Rate Maturity Amount Exelon Corporate Senior Unsecured Notes 4.55% June 15, 2015 $550 Exelon Corporate Senior Notes 4.90% June 15, 2015 800 Exelon Corporate Senior Unsecured Notes 3.95% June 15, 2025 443 Exelon Corporate Senior Unsecured Notes 4.95% June 15, 2035 167 Exelon Corporate Senior Unsecured Notes 5.10% June 15, 2045 259 Exelon Corporate Long Term Software License Agreement 3.95% May 1, 2024 1 Generation Senior Unsecured Notes 4.55% June 15, 2015 550 Generation CEU Upstream Nonrecourse Debt LIBOR + 2.25% January 14, 2019 9 Generation AVSR DOE Nonrecourse Debt 2.29% - 3.56% January 5, 2037 23 Generation Kennett Square Capital Lease 7.83% September 20,2020 3 Generation Continental Wind Nonrecourse Debt 6.00% February 28, 2033 20 Generation ExGen Texas Power Nonrecourse Debt LIBOR + 4.75% September 8, 2021 5 Generation ExGen Renewables I Nonrecourse Debt LIBOR + 4.25% February 6, 2021 24 Generation Constellation Solar Horizons Nonrecourse Debt 2.56% September 7, 2030 2 Generation Sacramento PV Energy Nonrecourse Debt 2.58% December 31, 2030 2 Generation Energy Efficiency Project 3.55% November 15, 2016 19 ComEd First Mortgage Bonds, Series 101 4.70% April 15, 2015 260 BGE Rate Stabilization Bonds 5.72% April 1, 2016 75 (a)As part of the 2012 Constellation merger, Exelon and subsidiaries of Generation assumed intercompany loan agreements that mirrored the terms and amounts of externalobligations held by Exelon, resulting in intercompany notes payable at Generation and Exelon Corporate.(b)See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of the redemption of the Senior Unsecured Notes.(c)See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt. On January 5, 2016, Generation paid down $5 million of principal of its 3.56% AVSR DOE Nonrecourse debt. 159(a)(b)(b)(b)(a)(c)(c)(c)(c)(c)(c)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Senior Unsecured Notes 5.35% January 15, 2014 $500 Generation Pollution Control Notes 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 Clean Horizons Solar Nonrecourse Debt 2.56% September 7, 2030 2 Generation Sacramento Solar Nonrecourse Debt 2.56% December 31, 2030 2 Generation Energy Efficiency Project Financing 4.12% December 31, 2015 12 ComEd First 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 During the year ended December 31, 2013, the following long term debt was retired and/or redeemed: Company Type Interest Rate Maturity Amount Generation Kennett Square Capital Lease 7.83% September 1, 2020 3 Generation Solar Revolver Nonrecourse Debt Variable Rate July 7, 2014 113 Generation Constellation Solar Horizons Nonrecourse Debt 2.56% September 7, 2030 2 Generation Sacramento Energy Nonrecourse Debt 2.68% December 31, 2030 2 Generation 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 Constellation merger on March 12, 2012 that became callable at face value on June 15, 2013. Exelon andsubsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations ofExelon, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. The debentures were redeemed and the intercompany loan agreements repaid onJune 15, 2013. 160(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsFrom 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 for the year ended December 31, 2015, 2014 and 2013 by Registrant were as follows: 2015 2014 2013 Exelon $1,105 $1,486 1,249 Generation 2,474 1,066 625 ComEd 299 307 220 PECO 279 320 333 BGE 171 13 13 (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 and 2014 activity includes CENG on a fully consolidated basis beginningApril 1, 2014.(b)Includes dividends paid on BGE’s preference stock. Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2015 and for the first quarter of 2016were as follows: Period Declaration Date Shareholder of RecordDate Dividend Payable Date Cash per Share First Quarter 2015 January 27, 2015 February 13, 2015 March 10, 2015 $0.31 Second Quarter 2015 April 28, 2015 May 15, 2015 June 10, 2015 $0.31 Third Quarter 2015 July 28, 2015 August 14, 2015 September 10, 2015 $0.31 Fourth Quarter 2015 October 27, 2015 November 13, 2015 December 10, 2015 $0.31 First Quarter 2016 January 26, 2016 February 12, 2016 March 10, 2016 $0.31 (a)Exelon’s Board of Directors approved a revised dividend policy. The approved policy would raise our dividend 2.5% each year for the next three years, beginning with the June2016 dividend. The Board will take formal action to declare the next dividend in the second quarter. Short-Term Borrowings. Short-term borrowings incurred (repaid) during 2015, 2014 and 2013 by Registrant were as follows: 2015 2014 2013 Generation $— $17 $13 ComEd (10) 120 184 BGE 90 (15) 135 Other — — — Exelon $80 $122 $332 (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 activity includes CENG on a fully consolidated basis.(b)Other primarily consists of corporate operations and BSC. 161(a)(a)(b) (a)(a) (b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsRetirement of Long-Term Debt to Financing Affiliates. There were no retirements of long-term debt to financing affiliates during 2015,2014 and 2013 by the Registrants. Contributions from Parent/Member. Contributions from Parent/Member (Exelon) during 2015, 2014 and 2013 by Registrant were asfollows: 2015 2014 2013 Generation $47 $53 $26 ComEd 209 278 176 PECO 16 24 27 BGE 7 — — (a)Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernizationpursuant to EIMA, transmission upgrades and expansions and Exelon’s agreement to indemnify ComEd for any unfavorable after-tax impacts associated with ComEd’s LKE taxmatter. Other. For the year ended December 31, 2015, other financing activities primarily consists of debt issuance costs. See Note 14—Debt andCredit Agreements of the Combined Notes to Consolidated Financial Statements’ for additional information. Credit Matters Market Conditions The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cashflows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include$8.4 billion in aggregate total commitments of which $6.9 billion was available as of December 31, 2015, and of which no financial institution hasmore than 7% of the aggregate commitments for Exelon, Generation, ComEd, PECO and BGE. The Registrants had access to the commercialpaper market during 2015 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. RISKFACTORS for further information regarding the effects of uncertainty in the capital and credit markets. The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficientliquidity. If Generation lost its investment grade credit rating as of December 31, 2015, it would have been required to provide incremental collateralof $2.0 billion to meet 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 $4.3 billion. If ComEd lost its investment grade credit ratings as of December 31, 2015, it would have been required to provide collateral of $31million pursuant to PJM’s credit policy and could have been required to provide incremental collateral of $19 million which is well within its currentavailable credit facility capacity of $998 million. If PECO lost its investment grade credit rating as of December 31, 2015 it would have beenrequired to provide collateral of $2 million pursuant to PJM’s credit policy and could have been required to provide collateral of $25 million relatedto its natural gas procurement contracts, which, in the aggregate, are well within PECO’s current available credit facility capacity of $599 million. IfBGE lost its investment grade credit rating as of December 31, 2015 it would have been required to 162(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsprovide collateral of $6 million pursuant to PJM’s credit policy and could have been required to provide collateral of $35 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 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. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term fundingrequirements and the issuance of letters of credit. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated FinancialStatements for discussion of the Registrants’ credit facilities and short term borrowing activity. Other Credit Matters Capital Structure. At December 31, 2015, the capital structures of the Registrants consisted of the following: Exelon Generation ComEd PECO BGE Long-term debt 47% 37% 43% 43% 34% Long-term debt to affiliates 1% 4% 1% 3% 5% Common equity 51% — 54% 54% 53% Member’s equity — 59% — — — Preference Stock — — — — 4% Commercial paper and notes payable 1% — 2% — 4% (a)Includes approximately $641 million, $205 million, $184 million and $252 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, 2015, in addition to the net contribution or borrowing as of December 31,2015, are presented in the following table: MaximumContributed MaximumBorrowed December 31, 2015Contributed(Borrowed) Generation $3 $1,709 $(1,252) PECO — 100 — BSC — 413 (226) Exelon Corporate 2,008 — 1,478 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 establish limits on the concentration of holdings in any one company and also in any one 163 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsindustry. See Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for further informationregarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications. Shelf Registration Statements. The Registrants have a currently effective combined shelf registration statement unlimited in amount, filedwith the SEC, that will expire in May 2017. The ability of each Registrant to sell securities off the shelf registration statement or to access theprivate placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, asapplicable, the current financial condition of the Registrant, its securities ratings and market conditions. Regulatory Authorizations. As of December 31, 2015, ComEd had $442 million available in long-term debt refinancing authority and $353million available in new money long-term debt financing authority from the ICC. In November 2015, the PAPUC approved PECO’s application forlong-term financing for $2.5 billion, which is effective through December 31, 2018. As of December 31, 2015, PECO had $1.9 billion available inlong-term debt financing authority from the PAPUC. As of December 31, 2015, BGE had $1.4 billion available in long-term financing authority fromMDPSC. As of December 31, 2015, ComEd, PECO and BGE had short-term financing authority from FERC, which expires on December 31, 2017, of$2.5 billion, $1.5 billion and $700 million, respectively. Generation currently has blanket financing authority it received from FERC in connectionwith its market-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 was 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, 2015, Exelon had retainedearnings of $12,068 million, including Generation’s undistributed earnings of $2,701 million, ComEd’s retained earnings of $978 million consistingof retained earnings appropriated for future dividends of $2,617 million partially offset by $1,639 million of unappropriated retained deficit, PECO’sretained earnings of $780 million and BGE’s retained earnings $1,320 million. See Note 23—Commitments and Contingencies of the CombinedNotes to Consolidated Financial Statements for additional information regarding fund transfer restrictions. 164Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 under existing contractualobligations, including payments due by period. See Note 23—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 2016 2017-2018 2019-2020 Due 2021and beyond AllOther Long-term debt $25,732 $1,483 $3,226 $4,275 $16,748 $— Interest payments on long-term debt 14,459 1,146 2,122 1,863 9,328 — Liability and interest for uncertain tax positions 860 860 — — — — Capital leases 29 4 8 9 8 — Operating leases 1,174 133 195 144 702 — Purchase power obligations 1,692 506 717 212 257 — Fuel purchase agreements 9,382 1,448 2,460 1,919 3,555 — Electric supply procurement 1,563 993 570 — — — AEC purchase commitments 6 1 2 3 — — Curtailment services commitments 99 37 55 7 — — Long-term renewable energy and REC commitments 1,443 76 155 165 1,047 — Other purchase obligations 4,578 2,420 940 421 797 — Construction commitments 1,272 821 451 — — PJM regional transmission expansion commitments 737 375 293 69 — — Spent nuclear fuel obligation 1,021 — — — 1,021 — Pension minimum funding requirement 1,412 250 500 500 162 — Total contractual obligations $65,459 $10,553 $11,694 $9,587 $33,625 $— (a)Includes $648 million due after 2021 to ComEd, PECO and BGE financing trusts.(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2015 and do not reflect anticipated future refinancing, earlyredemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2015. Includes estimated interest payments due to ComEd,PECO and BGE financing trusts.(c)In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon would be required to either post a bond or pay the tax and interest for the taxyears before the court to appeal the decision. If an adverse decision is reached in 2016, the potential tax and after-tax interest, exclusive of penalties, that could become payablemay be as much as $860 million, of which approximately $300 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless from anyunfavorable impacts of the after-tax interest amounts on ComEd’s equity, and the balance at Exelon. It is expected that Exelon’s remaining tax years affected by the litigation willbe settled following a final appellate decision which could take several years.(d)Excludes Generation’s contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations.Includes estimated cash payments for service fees related to PECO’s meter reading operating lease.(e)Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’sexpected payments under these arrangements at December 31, 2015, 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 165(a)(b)(c)(d)(e)(f)(f)(f)(f)(g)(h)(i)(j)(k)(l)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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.(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 the future estimated value at December 31, 2015 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between theRegistrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. Theseestimates are subject to significant variability from period to period.(i)Represents commitments for Generation’s ongoing investments in renewables development, new natural gas and biomass generation construction. Amount includes $421 millionof remaining commitments related to the construction of new combined-cycle gas turbine units in Texas. Achievement of commercial operations related to this project is expected in2017.(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 23—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. The projected contributions reflect a funding strategy of contributing the greater of $250million until the qualified plans are fully funded on an accumulated benefit obligation basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk statusthereafter. The remaining qualified pension plans’ contributions are generally based on the estimated minimum pension contributions required under ERISA and the PensionProtection Act of 2006, as well as contributions necessary to avoid benefit restrictions and at-risk status. These amounts represent estimates that are based on assumptions thatare subject to change. The minimum required contributions for years after 2021 are not included. See Note 17—Retirement Benefits of the Combined Notes to ConsolidatedFinancial Statements for further information regarding estimated future pension benefit payments. Generation Payment due within Total 2016 2017-2018 2019-2020 Due 2021and beyond AllOther Long-term debt $8,898 $87 $849 $2,575 $5,387 $— Interest payments on long-term debt 5,452 424 792 684 3,552 — Capital leases 21 4 8 9 — — Operating leases 956 86 126 89 655 — Purchase power obligations 1,692 506 717 212 257 — Fuel purchase agreements 8,450 1,211 2,167 1,777 3,295 — Other purchase obligations 2,193 928 392 225 648 — Construction commitments 1,272 821 451 — — Spent nuclear fuel obligation 1,021 — — — 1,021 — Total contractual obligations $29,955 $4,067 $5,502 $5,571 $14,815 $— (a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2015 and do not reflect anticipated future refinancing, earlyredemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2015.(b)See Note 23—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding spent nuclear fuel obligations.(c)Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.(d)Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’sexpected payments under these arrangements at December 31, 2015. 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.(e)Represents commitments to purchase fuel supplies for nuclear and fossil generation. 166 (a) (c) (d) (e)(f)(g)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 the future estimated value at December 31, 2015 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between theRegistrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. Theseestimates are subject to significant variability from period to period.(g)Represents commitments for Generation’s ongoing investments in renewables development, new natural gas and biomass generation construction. Amount includes $421 millionof remaining commitments related to the construction of new combined-cycle gas turbine units in Texas. Achievement of commercial operations related to this project is expected in2017. ComEd Payment due within Total 2016 2017-2018 2019-2020 Due 2021and beyond AllOther Long-term debt $6,765 $665 $1,265 $800 $4,035 $— Interest payments on long-term debt 4,597 297 523 420 3,357 — Liability and interest for uncertain tax positions 300 300 — — — — Capital leases 8 — — — 8 — Operating leases 37 14 14 8 1 — Electric supply procurement 739 453 286 — — — Long-term renewable energy and associated REC commitments 1,444 76 156 165 1,047 — Other purchase obligations 699 565 94 39 1 — PJM regional transmission expansion commitments 297 204 87 6 — — Total contractual obligations $14,886 $2,574 $2,425 $1,438 $8,449 $— (a)Includes $206 million due after 2021 to a ComEd financing trust.(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2015 and do not reflect anticipated future refinancing, earlyredemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2015. Includes estimated interest payments due to the ComEdfinancing trust.(c)In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon would be required to either post a bond or pay the tax and interest for the taxyears before the court to appeal the decision. If an adverse decision is reached in 2016, the potential tax and after-tax interest, exclusive of penalties, that could become payablemay be as much as $860 million, of which approximately $300 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless from anyunfavorable impacts of the after-tax interest amounts on ComEd’s equity, and the balance at Exelon. It is expected that Exelon’s remaining tax years affected by the litigation willbe settled following a final appellate decision which could take several years.(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 the future estimated value at December 31, 2015 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between theRegistrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. Theseestimates are subject to significant variability from period to period.(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. 167 (a) (b) (c) (d)(e) (f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2016 2017-2018 2019-2020 Due 2021and beyond AllOther Long-term debt $2,784 $300 $500 $— $1,984 $— Interest payments on long-term debt 1,771 115 207 176 1,273 — Operating leases 12 3 5 4 — — Fuel purchase agreements 357 125 137 35 60 — Electric supply procurement 622 516 106 — — — AEC purchase commitments 9 2 4 3 — — Other purchase obligations 215 174 18 22 1 — PJM regional transmission expansion commitments 67 31 32 4 — — Total contractual obligations $5,837 $1,266 $1,009 $244 $3,318 $— (a)Includes $184 million due after 2021 to PECO 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)Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs.(d)Represents the future estimated value at December 31, 2015 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between theRegistrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. Theseestimates are subject to significant variability from period to period.(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 2016 2017-2018 2019-2020 Due 2021and beyond AllOther Long-term debt $2,128 $378 $42 $— $1,708 $— Interest payments on long-term debt 1,353 82 159 159 953 — Operating leases 65 12 19 15 19 — Fuel purchase agreements 575 112 156 107 200 — Electric supply procurement 1,427 860 567 — — — Curtailment services commitments 99 37 55 7 — — Other purchase obligations 635 408 208 17 2 — PJM regional transmission expansion commitments 373 140 174 59 — — Total contractual obligations $6,655 $2,029 $1,380 $364 $2,882 $— (a)Includes $258 million due after 2021 to the BGE financing trusts.(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2015 and do not reflect anticipated future refinancing, earlyredemptions or debt issuances.(c)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.(d)Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services.(e)Represents the future estimated value at December 31, 2015 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between theRegistrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. Theseestimates are subject to significant variability from period to period. 168 (a) (b) (c) (c) (c)(d) (e) (a) (b) (d) (d) (d)(e) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 23—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 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements. • long-term debt, see Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements. • liabilities related to uncertain tax positions, see Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements. • capital lease obligations, see Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements. • operating leases and rate relief commitments, see Note 23—Commitments and Contingencies of the Combined Notes to ConsolidatedFinancial Statements. • the nuclear decommissioning and SNF obligations, see Notes 16—Asset Retirement Obligations and 23—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 23—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. ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates 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. 169Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 2016 through 2018. 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. Exelon’s hedging program involves the hedging of commodity risk for Exelon’sexpected generation, typically on a ratable basis over a three year period. As of December 31, 2015, the proportion of expected generation hedgedis 90%-93%, 60%-63% and 28%-31% for 2016, 2017 and 2018, respectively. The percentage of expected generation hedged is the amount ofequivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position inenergy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future marketconditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedgingproducts, which include economic hedges and certain non-derivative contracts including Generation’s sales to ComEd, PECO and BGE to servetheir retail load. 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-proprietary trading portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on December 31, 2015, market conditions and hedged position would be a decrease in pre-tax net income ofapproximately $50 million, $400 million and $725 million, respectively, for 2016, 2017 and 2018. Power price sensitivities are derived by adjustingpower price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market pricerisk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, aswell 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 7,310 GWh, 10,571 GWh, and 8,762 GWhfor the years ended December 31, 2015, 2014 and 2013 respectively, are a complement to Generation’s energy marketing portfolio, but represent asmall portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the year endedDecember 31, 2015, resulted in pre-tax gains of $1 million due to net mark-to-market losses of $8 million and realized gains of $9 million.Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period, one-tailed statistical measure incalculating its VaR. The daily VaR on proprietary trading activity averaged $0.2 million of exposure during the year. Generation has not segregatedproprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to 170Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 total Revenue net of purchase power and fuel expense from continuing operations for the year ended December 31, 2015 of $9,114million. Fuel Procurement. Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases.Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrates supply contracts, contracted conversion services,contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentratesand certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’sprocurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity orservice at the contracted prices. Approximately 50% of Generation’s uranium concentrate requirements from 2016 through 2020 are supplied bythree producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can beobtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance bythese counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.See ITEM 7.—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additionalinformation regarding uranium and coal supply agreement matters. ComEd The financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby 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 energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments underthe existing 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 13—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. 171Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 Note13—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 Note13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements. Trading and Non-Trading Marketing Activities The following detailed presentation of Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activities is included to addressthe recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO). 172Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 detail on changes in Exelon’s, Generation’s, and ComEd’s commodity mark-to-market net asset or liabilitybalance sheet position from January 1, 2014 to December 31, 2015. 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 13—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, 2015 and December 31, 2014. Generation ComEd Exelon Total mark-to-market energy contract net assets (liabilities) at January 1, 2014 $1,047 $(193) $854 Contracts acquired at merger date 128 — 128 Total change in fair value during 2014 of contracts recorded in result of operations (608) — (608) Reclassification to realized at settlement of contracts recorded in results of operations (21) — (21) Reclassification to realized at settlement from accumulated OCI (195) — (195) Changes in fair value—energy derivatives — (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 Total change in fair value during 2015 of contracts recorded in result of operations 412 — 412 Reclassification to realized at settlement of contracts recorded in results of operations (168) — (168) Reclassification to realized at settlement from accumulated OCI (2) — (2) Changes in fair value—energy derivatives — (40) (40) Changes in allocated collateral (172) — (172) Changes in net option premium paid/(received) (58) — (58) Option premium amortization (21) — (21) Other balance sheet reclassifications 50 — 50 Total mark-to-market energy contract net assets (liabilities) at December 31, 2015 $1,753 $(247) $1,506 (a)Amounts are shown net of cash collateral paid to and received from counterparties.(b)For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2015 and 2014, ComEd recorded a regulatory liability of$247 million and $207 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. Includes $55 million of decreases in fairvalue and an increase for realized losses due to settlements off $(15) million recorded in purchased power expense associated with floating-to-fixed energy swap contracts withunaffiliated suppliers for the year ended December 31, 2015. Includes $13 million of decreases in fair value and a reduction for realized gains due to settlements of $1 million forthe year ended December 31, 2014.(c)Includes $81 million of fair value from contracts acquired and $47 million of cash collateral as a result of the Integrys acquisition.(d)Other balance sheet reclassifications include derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums. 173 (a) (c) (b) (d) (a)(b) (d)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 12—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 TotalFairValue 2016 2017 2018 2019 2020 2021 andBeyond Normal Operations, Commodity derivative contracts: Actively quoted prices (Level 1) $37 $27 $(19) $(19) $(7) $— $19 Prices provided by external sources(Level 2) 540 165 (8) (8) (6) — 683 Prices based on model or other valuation methods (Level 3) 572 255 95 (26) (23) (69) 804 Total $1,149 $447 $68 $(53) $(36) $(69) $1,506 (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 $1,234 million at December 31, 2015.(c)Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. Generation Maturities Within TotalFairValue 2016 2017 2018 2019 2020 2021andBeyond Normal Operations, Commodity derivative contracts: Actively quoted prices (Level 1) $37 $27 $(19) $(19) $(7) $— $19 Prices provided by external sources (Level 2) 540 165 (8) (8) (6) — 683 Prices based on model or other valuation methods (Level 3) 595 276 116 (5) (1) 70 1,051 Total $1,172 $468 $89 $(32) $(14) $70 $1,753 (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 $1,234 million at December 31, 2015. 174 (a)(b) (c) (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Maturities Within FairValue 2016 2017 2018 2019 2020 2021 andBeyond Prices based on model or other valuation methods (Level 3) $(23) $(21) $(21) $(21) $(22) $(139) $(247) (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 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk,collateral, and contingent related features. Generation 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, 2015. 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 $15 million, $36 million and $31 million, respectively. See Note 26—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information. Rating as of December 31, 2015 TotalExposureBefore CreditCollateral Credit Collateral NetExposure Number ofCounterpartiesGreater than 10%of Net Exposure Net Exposure ofCounterpartiesGreater than 10%of Net Exposure Investment grade $1,397 $50 $1,347 1 $432 Non-investment grade 67 25 42 — — No external ratings Internally rated—investment grade 521 — 521 — — Internally rated—non-investmentgrade 77 7 70 — — Total $2,062 $82 $1,980 1 $432 175 (a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Maturity of Credit Risk Exposure Rating as of December 31, 2015 Less than2 Years 2-5Years ExposureGreater than5 Years Total ExposureBefore CreditCollateral Investment grade $1,036 $343 $18 $1,397 Non-investment grade 40 19 8 67 No external ratings Internally rated—investment grade 452 46 23 521 Internally rated—non-investment grade 71 6 — 77 Total $1,599 $414 $49 $2,062 Net Credit Exposure by Type of Counterparty As ofDecember 31,2015 Financial institutions $187 Investor-owned utilities, marketers, power producers 886 Energy cooperatives and municipalities 872 Other 35 Total $1,980 (a)As of December 31, 2015, credit collateral held from counterparties where Generation had credit exposure included $13 million of cash and $69 million of letters of credit. ComEd Credit risk for ComEd is managed by credit and collection policies, which are consistent with state regulatory requirements. ComEd 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, 2015. 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 176Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsrecover realized energy costs through customer rates. As of December 31, 2015, 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, 2015. 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, 2015, PECO had no net creditexposure with suppliers. PECO does not obtain cash collateral from suppliers under its natural gas supply and asset management agreements. As of December 31,2015, PECO’s credit exposure under its natural gas supply and asset management agreements with investment grade suppliers was immaterial. 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, 2015. 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 177Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsa transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceedsthe initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured creditlimit. The seller’s credit exposure is calculated each business day. As of December 31, 2015, BGE had no net credit exposure with suppliers. BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to 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, 2015, BGE had credit exposure of $4 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, natural gas 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 andcircumstances 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 13—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 is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties arerequired to post collateral with Generation. In order to post collateral, Generation depends on access to bank credit facilities, which serve asliquidity sources to fund collateral requirements. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated FinancialStatements for additional information. As of December 31, 2015, Generation had cash collateral of $1,267 million posted and cash collateral held of $21 million for externalcounterparties with derivative positions, of which $1,234 million and $9 million in net cash collateral deposits were offset against energy derivativesand interest rate and foreign exchange derivatives related to underlying energy contracts, respectively. As of December 31, 2015, $3 million ofcash collateral deposits was not offset against net derivative positions because it was not associated with energy-related derivatives or as of thebalance sheet date there were no positions to offset. As of December 31, 2014, Generation had cash collateral posted of $1,497 million and cashcollateral held of $77 million for external counterparties with derivative positions, of which $1,406 million and $6 million in net cash collateraldeposits were offset against 178Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 derivatives and interest rate and foreign exchange derivatives 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-relatedderivatives or as the balance sheet date there were no positions to offset. See Note 23—Commitments and Contingencies of the Combined Notesto Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral. ComEd As of December 31, 2015, ComEd held no collateral from suppliers in association with standard block energy procurement contracts andheld approximately $19 million in the form of cash and letters of credit for renewable energy contracts. See Note 3—Regulatory Matters and Note13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. PECO As of December 31, 2015, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 13—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, 2015, 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 Note13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information. RTOs and ISOs (Exelon, Generation, ComEd, PECO and BGE) Generation, ComEd, PECO and BGE participate in all, or some, of the established, real-time energy markets that are administered by PJM,ISO-NE, ISO-NY, 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. 179Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsLong-Term Leases (Exelon) Exelon’s Consolidated Balance Sheet, as of December 31, 2015, included a $352 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$639 million, less unearned income of $287 million. As of December 31, 2014, Exelon’s Consolidated Balance Sheet included a $361 million netinvestment in coal-fired plants in Georgia subject to long-term leases, which represented the estimated residual value of leased assets at the endof the respective lease terms of $685 million, less unearned income of $324 million. The lease agreements provide the lessees with fixed purchaseoptions at the end of the lease terms. If the lessee does not exercise the fixed purchase options, Exelon has the ability to operate the stations andkeep or market the power itself or require the lessee to arrange for a third-party to bid on a service contract for a period following the lease term.Exelon will be subject to residual value risk if the lessee does not exercise the fixed purchase options. This risk is partially mitigated by the fairvalue of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the servicecontract is less than the expected remaining useful life of the plants and, therefore, Exelon’s exposure to residual value risk will not be mitigatedby payments under the service contract in this remaining period. Lessee performance under the lease agreements is supported by collateral andcredit enhancement measures. Management regularly evaluates the creditworthiness of Exelon’s counterparties to these long-term leases. Exelonmonitors the continuing credit quality of the credit enhancement party. 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 fair value below the carrying value and the decline is determined to be other thantemporary, must record an impairment charge in the period the estimate changed. Based on the annual review performed in the second quarters of2015 and 2014, the estimated residual value of Exelon’s direct financing leases for the Georgia generating stations experienced other thantemporary declines given increases in estimated long-term operating and maintenance costs in the 2015 annual review and reduced long-termenergy and capacity price expectations in the 2014 annual review. As a result, Exelon recorded a $24 million pre-tax impairment charge in 2015and 2014 for these stations. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements forfurther 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, 2015, Exelon had $800 million of notionalamounts of fixed-to-floating hedges outstanding and Exelon and Generation had $738 million of notional amounts of floating-to-fixed hedgesoutstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest ratesassociated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $6 milliondecrease in Exelon Consolidated pre-tax income for the year ended December 31, 2015. To manage foreign exchange rate exposure associatedwith international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typicallydesignated as economic hedges. 180Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of ContentsEquity 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, 2015, 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 $454 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. 181Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Power Regions.These segments are discussed in further detail in “ITEM 1. BUSINESS—Exelon Generation Company, LLC” of this Form 10-K. Executive Overview A discussion of items pertinent to Generation’s executive overview is set forth under “ITEM 7. MANAGEMENT’S DISCUSSION ANDANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Exelon Corporation—Executive Overview” of this Form 10-K. Results of Operations Year Ended December 31, 2015 Compared To Year Ended December 31, 2014 and Year Ended December 31, 2014 Compared to YearEnded December 31, 2013 A discussion of Generation’s results of operations for 2015 compared to 2014 and 2014 compared to 2013 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 $5.7 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 14 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. Cash Flows from Operating Activities A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities”in “EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K. 182Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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, PECO and BGE—Critical Accounting Policies and Estimates above for a discussion of Generation’scritical accounting policies and estimates. New Accounting Pronouncements See Note 1 of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements. ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Generation Generation is exposed to market risks associated with commodity price, credit, interest rates and equity price. These risks are describedabove under “Quantitative and Qualitative Disclosures about Market Risk—Exelon.” 183Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Compared to Year Ended December 31, 2014 and Year Ended December 31, 2014 Compared to YearEnded December 31, 2013 A discussion of ComEd’s results of operations for 2015 compared to 2014 and for 2014 compared to 2013 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, 2015, 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 14 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. 184Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, PECO and BGE—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.” 185Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Compared to Year Ended December 31, 2014 and Year Ended December 31, 2014 Compared to YearEnded December 31, 2013 A discussion of PECO’s results of operations for 2015 compared to 2014 and for 2014 compared to 2013 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, 2015, 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. 186Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, PECO and BGE—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.” 187Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Compared to Year Ended December 31, 2014 and Year Ended December 31, 2014 Compared to YearEnded December 31, 2013 A discussion of BGE’s results of operations for 2015 compared to 2014 and for 2014 compared to 2013 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, 2015, 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. 188Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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.” 189Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 31,2015. 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 31,2015, Exelon’s internal control over financial reporting was effective. The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2015, has been audited byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 10, 2016 190Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015. 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, 2015, Generation’s internal control over financial reporting was effective. The effectiveness of Generation’s internal control over financial reporting as of December 31, 2015, has been audited byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 10, 2016 191Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015. 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, 2015, ComEd’s internal control over financial reporting was effective. The effectiveness of ComEd’s internal control over financial reporting as of December 31, 2015, has been audited byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 10, 2016 192Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 31,2015. 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 31,2015, PECO’s internal control over financial reporting was effective. The effectiveness of PECO’s internal control over financial reporting as of December 31, 2015, has been audited byPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. February 10, 2016 193Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 31,2015. 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 31,2015, BGE’s internal control over financial reporting was effective. The effectiveness of BGE’s internal control over financial reporting as of December 31, 2015, has been audited by PricewaterhouseCoopersLLP, an independent registered public accounting firm, as stated in their report which appears herein. February 10, 2016 194Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014 and the results of their operationsand their cash flows for each of the three years in the period ended December 31, 2015 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)present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015,based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, formaintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting,included in Management’s Report on Internal Control over Financial Reporting appearing under Item 8. Our responsibility is to express opinions onthese financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on ourintegrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free ofmaterial misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of thefinancial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessingthe accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Ouraudit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the riskthat a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide areasonable 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 10, 2016 195Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014 and the results oftheir operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 10, 2016 196Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014, and the results oftheir operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 10, 2016 197Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014 and the results of theiroperations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 10, 2016 198Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014 and the resultsof their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 10, 2016 199Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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] 200Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Operating revenues Competitive businesses revenues $18,395 $16,637 $14,277 Rate-regulated utility revenues 11,052 10,792 10,611 Total operating revenues 29,447 27,429 24,888 Operating expenses Competitive businesses purchased power and fuel 10,007 9,369 6,928 Rate-regulated utility purchased power and fuel 3,077 3,103 2,540 Purchased power and fuel from affiliates — 531 1,256 Operating and maintenance 8,322 8,568 7,270 Depreciation and amortization 2,450 2,314 2,153 Taxes other than income 1,200 1,154 1,095 Total operating expenses 25,056 25,039 21,242 Equity in (losses) earnings of unconsolidated affiliates — (20) 10 Gain on sales of assets 18 437 13 Gain on consolidation and acquisition of businesses — 289 — Operating income 4,409 3,096 3,669 Other income and (deductions) Interest expense, net (992) (1,024) (1,315) Interest expense to affiliates, net (41) (41) (41) Other, net (46) 455 460 Total other income and (deductions) (1,079) (610) (896) Income before income taxes 3,330 2,486 2,773 Income taxes 1,073 666 1,044 Equity in losses of unconsolidated affiliates (7) — — Net income 2,250 1,820 1,729 Net income (loss) attributable to noncontrolling interest and preference stock dividends (19) 197 10 Net income attributable to common shareholders $2,269 $1,623 $1,719 Comprehensive income, net of income taxes Net income $2,250 $1,820 $1,729 Other comprehensive income (loss), net of income taxes Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost (46) (30) — Actuarial loss reclassified to periodic benefit cost 220 147 208 Pension and non-pension postretirement benefit plan valuation adjustment (99) (497) 669 Unrealized gain (loss) on cash flow hedges 9 (148) (248) Unrealized gain on marketable securities — 1 2 Unrealized gain (loss) on equity investments (3) 8 106 Unrealized loss on foreign currency translation (21) (9) (10) Reversal of CENG equity method AOCI — (116) — Other comprehensive income (loss) 60 (644) 727 Comprehensive income $2,310 $1,176 $2,456 Average shares of common stock outstanding: Basic 890 860 856 Diluted 893 864 860 Earnings per average common share: Basic $2.55 $1.89 $2.01 Diluted $2.54 $1.88 $2.00 Dividends per common share $1.24 $1.24 $1.46 See the Combined Notes to Consolidated Financial Statements 201Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Cash flows from operating activities Net income $2,250 $1,820 $1,729 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contractamortization 3,987 3,868 3,779 Impairment of long-lived assets 36 687 171 Gain on consolidation and acquisition of businesses — (296) — Gain on sales of assets (18) (437) (13) Deferred income taxes and amortization of investment tax credits 752 502 119 Net fair value changes related to derivatives (367) 716 (445) Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments 131 (210) (170) Other non-cash operating activities 1,109 1,054 718 Changes in assets and liabilities: Accounts receivable 240 (318) (97) Inventories 4 (380) (100) Accounts payable and accrued expenses (121) 49 (116) Option premiums received (paid), net 58 38 (36) Collateral received (posted), net 347 (1,719) 215 Income taxes 97 (143) 883 Pension and non-pension postretirement benefit contributions (502) (617) (422) Other assets and liabilities (387) (157) 128 Net cash flows provided by operating activities 7,616 4,457 6,343 Cash flows from investing activities Capital expenditures (7,624) (6,077) (5,395) Proceeds from termination of direct financing lease investment — 335 — Proceeds from nuclear decommissioning trust fund sales 6,895 7,396 4,217 Investment in nuclear decommissioning trust funds (7,147) (7,551) (4,450) Cash and restricted cash acquired from consolidations and acquisitions — 140 — Acquisitions of businesses (40) (386) — Proceeds from sales of long-lived assets 147 1,719 32 Proceeds from sales of investments — 7 22 Purchases of investments — (3) (4) Change in restricted cash 66 (104) (43) Distribution from CENG — 13 115 Other investing activities (119) (88) 112 Net cash flows used in investing activities (7,822) (4,599) (5,394) Cash flows from financing activities Payment of accounts receivable agreement — — (210) Changes in short-term borrowings 80 122 332 Issuance of long-term debt 6,709 3,463 2,055 Retirement of long-term debt (2,687) (1,545) (1,589) Issuance of common stock 1,868 — — Redemption of preferred securities — — (93) Distributions to noncontrolling interest of consolidated VIE — (421) — Dividends paid on common stock (1,105) (1,065) (1,249) Proceeds from employee stock plans 32 35 47 Other financing activities (67) (178) (119) Net cash flows provided by (used in) financing activities 4,830 411 (826) Increase in cash and cash equivalents 4,624 269 123 Cash and cash equivalents at beginning of period 1,878 1,609 1,486 Cash and cash equivalents at end of period $6,502 $1,878 $1,609 See the Combined Notes to Consolidated Financial Statements 202Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 ASSETS Current assets Cash and cash equivalents $6,502 $1,878 Restricted cash and cash equivalents 205 271 Accounts receivable, net Customer 3,187 3,482 Other 912 1,227 Mark-to-market derivative assets 1,365 1,279 Unamortized energy contract assets 86 254 Inventories, net Fossil fuel 462 579 Materials and supplies 1,104 1,024 Regulatory assets 759 847 Assets held for sale 4 147 Other 748 865 Total current assets 15,334 11,853 Property, plant and equipment, net 57,439 52,170 Deferred debits and other assets Regulatory assets 6,065 6,076 Nuclear decommissioning trust funds 10,342 10,537 Investments 639 544 Goodwill 2,672 2,672 Mark-to-market derivative assets 758 773 Unamortized energy contract assets 484 549 Pledged assets for Zion Station decommissioning 206 319 Other 1,445 923 Total deferred debits and other assets 22,611 22,393 Total assets $95,384 $86,416 See the Combined Notes to Consolidated Financial Statements 203 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term borrowings $533 $460 Long-term debt due within one year 1,500 1,802 Accounts payable 2,883 3,048 Accrued expenses 2,376 1,539 Payables to affiliates 8 8 Regulatory liabilities 369 310 Mark-to-market derivative liabilities 205 234 Unamortized energy contract liabilities 100 238 Renewable energy credit obligation 302 192 Other 842 931 Total current liabilities 9,118 8,762 Long-term debt 23,645 19,212 Long-term debt to financing trusts 641 641 Deferred credits and other liabilities Deferred income taxes and unamortized investment tax credits 13,776 12,778 Asset retirement obligations 8,585 7,295 Pension obligations 3,385 3,366 Non-pension postretirement benefit obligations 1,618 1,742 Spent nuclear fuel obligation 1,021 1,021 Regulatory liabilities 4,201 4,550 Mark-to-market derivative liabilities 374 403 Unamortized energy contract liabilities 117 211 Payable for Zion Station decommissioning 90 155 Other 1,491 2,147 Total deferred credits and other liabilities 34,658 33,668 Total liabilities 68,062 62,283 Commitments and contingencies Contingently redeemable noncontrolling interest 28 — Shareholders’ equity Common stock (No par value, 2000 shares authorized, 920 shares and 860 shares outstanding at December 31,2015 and 2014, respectively) 18,676 16,709 Treasury stock, at cost (35 shares at December 31, 2015 and 2014, respectively) (2,327) (2,327) Retained earnings 12,068 10,910 Accumulated other comprehensive loss, net (2,624) (2,684) Total shareholders’ equity 25,793 22,608 BGE preference stock not subject to mandatory redemption 193 193 Noncontrolling interest 1,308 1,332 Total equity 27,294 24,133 Total liabilities and shareholders’ equity $95,384 $86,416 (a)Exelon’s consolidated assets include $8,268 million and $8,159 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used tosettle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,264 million and $2,728 million at December 31, 2015 and December 31, 2014, respectively, of certainVIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities. See the Combined Notes to Consolidated Financial Statements 204(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2012 889,525 $16,632 $(2,327) $9,893 $(2,767) $106 $193 $21,730 Net income (loss) — — — 1,719 — (10) 20 1,729 Long-term incentive plan activity 1,445 81 — — — — — 81 Employee stock purchase plan issuances 1,064 28 — — — — — 28 Common stock dividends — — — (1,254) — — — (1,254) Consolidated VIE dividend to noncontrolling interest — — — — — (63) — (63) Deconsolidation of VIE — — — — — (18) — (18) Redemption of preferred securities — — — — — — (6) (6) Preferred and preference stock dividends — — — — — — (14) (14) Other comprehensive income, net of income taxes — — — — 727 — — 727 Balance, December 31, 2013 892,034 $16,741 $(2,327) $10,358 $(2,040) $15 $193 $22,940 Net income — — — 1,623 — 184 13 1,820 Long-term incentive plan activity 1,574 72 — — — — — 72 Employee stock purchase plan issuances 960 35 — — — — — 35 Tax benefit on stock compensation — (8) — — — — — (8) Acquisition of noncontrolling interest — (2) — — — 6 — 4 Common stock dividends — — — (1,071) — — — (1,071) Preferred and preference stock dividends — — — — — — (13) (13) Fair value of financing contract payments — (131) — — — — — (131) Noncontrolling interest established upon consolidation ofCENG — — — — — 1,548 — 1,548 Transfer of CENG pension and non-pensionpostretirement benefit obligations — 2 — — — — — 2 Consolidated VIE dividend to noncontrolling interest — — — — — (421) — (421) Reversal of CENG equity method AOCI, net of incometaxes — — — — (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 Net income (loss) — — — 2,269 — (32) 13 2,250 Long-term incentive plan activity 1,430 70 — — — — — 70 Employee stock purchase plan issuances 1,170 32 — — — — — 32 Issuance of common stock 57,500 1,868 — — — — — 1,868 Tax benefit on stock compensation — (3) — — — — — (3) Acquisition of noncontrolling interest — — — — — 4 — 4 Adjustment of contingently redeemable noncontrollinginterest due to release of contingency — — — — — 4 — 4 Common stock dividends — — — (1,111) — — — (1,111) Preferred and preference stock dividends — — — — — — (13) (13) Other comprehensive loss, net of income taxes — — — — 60 — — 60 Balance, December 31, 2015 954,668 $18,676 $(2,327) $12,068 $(2,624) $1,308 $193 $27,294 See the Combined Notes to Consolidated Financial Statements 205Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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] 206Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Operating revenues Operating revenues $18,386 $16,614 $14,207 Operating revenues from affiliates 749 779 1,423 Total operating revenues 19,135 17,393 15,630 Operating expenses Purchased power and fuel 10,007 9,368 6,927 Purchased power and fuel from affiliates 14 557 1,270 Operating and maintenance 4,688 4,943 3,960 Operating and maintenance from affiliates 620 623 574 Depreciation and amortization 1,054 967 856 Taxes other than income 489 465 389 Total operating expenses 16,872 16,923 13,976 Equity in (losses) earnings of unconsolidated affiliates — (20) 10 Gain on sales of assets 12 437 13 Gain on consolidation and acquisition of businesses — 289 — Operating income 2,275 1,176 1,677 Other income and (deductions) Interest expense (322) (303) (298) Interest expense to affiliates, net (43) (53) (59) Other, net (60) 406 355 Total other income and (deductions) (425) 50 (2) Income before income taxes 1,850 1,226 1,675 Income taxes 502 207 615 Equity in losses of unconsolidated affiliates (8) — — Net income 1,340 1,019 1,060 Net income (loss) attributable to noncontrolling interests (32) 184 (10) Net income attributable to membership interest $1,372 $835 $1,070 Comprehensive income, net of income taxes Net income $1,340 $1,019 $1,060 Other comprehensive income (loss), net of income taxes Unrealized loss on cash flow hedges (3) (132) (398) Unrealized (loss) gain on equity investments (3) 8 107 Unrealized loss on foreign currency translation (21) (9) (10) Unrealized (loss) gain on marketable securities — (1) 2 Reversal of CENG equity method AOCI — (116) — Other comprehensive loss (27) (250) (299) Comprehensive income $1,313 $769 $761 See the Combined Notes to Consolidated Financial Statements 207Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Cash flows from operating activities Net income $1,340 $1,019 $1,060 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization 2,589 2,519 2,559 Impairment of long-lived assets 12 663 157 Gain on consolidation and acquisition of businesses — (296) — Gain on sales of assets (12) (437) (13) Deferred income taxes and amortization of investment tax credits 49 (198) 315 Net fair value changes related to derivatives (249) 635 (448) Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments 131 (210) (170) Other non-cash operating activities 268 346 270 Changes in assets and liabilities: Accounts receivable 194 (215) 109 Receivables from and payables to affiliates, net 15 15 2 Inventories 16 (359) (88) Accounts payable and accrued expenses (149) 29 (160) Option premiums received (paid), net 58 38 (36) Collateral received (posted), net 407 (1,748) 162 Income taxes (18) 265 402 Pension and non-pension postretirement benefit contributions (245) (297) (149) Other assets and liabilities (207) 57 (85) Net cash flows provided by operating activities 4,199 1,826 3,887 Cash flows from investing activities Capital expenditures (3,841) (3,012) (2,752) Proceeds from nuclear decommissioning trust fund sales 6,895 7,396 4,217 Investment in nuclear decommissioning trust funds (7,147) (7,551) (4,450) Cash and restricted cash acquired from consolidations and acquisitions — 140 — Proceeds from sales of long-lived assets 147 1,719 32 Acquisitions of businesses (40) (386) — Change in restricted cash 35 (87) (64) Changes in Exelon intercompany money pool — 44 (44) Distribution from CENG — 13 115 Other investing activities (118) (43) 30 Net cash flows used in investing activities (4,069) (1,767) (2,916) Cash flows from financing activities Change in short-term borrowings — 17 13 Issuance of long-term debt 1,309 1,112 854 Retirement of long-term debt (89) (586) (570) Retirement of long-term debt to affiliate (550) — — Changes in Exelon intercompany money pool 1,252 — — Distribution to member (2,474) (645) (625) Distribution to noncontrolling interest of consolidated VIE — (421) — Contribution from member 47 53 26 Other financing activities 26 (67) (82) Net cash flows used in financing activities (479) (537) (384) Increase (decrease) in cash and cash equivalents (349) (478) 587 Cash and cash equivalents at beginning of period 780 1,258 671 Cash and cash equivalents at end of period $431 $780 $1,258 See the Combined Notes to Consolidated Financial Statements 208Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 ASSETS Current assets Cash and cash equivalents $431 $780 Restricted cash and cash equivalents 123 158 Accounts receivable, net Customer 2,095 2,295 Other 360 318 Mark-to-market derivative assets 1,365 1,276 Receivables from affiliates 83 113 Unamortized energy contract assets 86 254 Inventories, net Fossil fuel 384 465 Materials and supplies 880 847 Assets held for sale 4 147 Other 531 658 Total current assets 6,342 7,311 Property, plant and equipment, net 25,843 23,028 Deferred debits and other assets Nuclear decommissioning trust funds 10,342 10,537 Investments 210 104 Goodwill 47 47 Mark-to-market derivative assets 733 771 Prepaid pension asset 1,689 1,704 Pledged assets for Zion Station decommissioning 206 319 Unamortized energy contract assets 484 549 Deferred income taxes 6 3 Other 627 578 Total deferred debits and other assets 14,344 14,612 Total assets $46,529 $44,951 See the Combined Notes to Consolidated Financial Statements 209(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 LIABILITIES AND EQUITY Current liabilities Short-term borrowings $29 $36 Long-term debt due within one year 90 58 Long-term debt to affiliates due within one year — 556 Accounts payable 1,583 1,759 Accrued expenses 935 886 Payables to affiliates 104 107 Borrowings from Exelon intercompany money pool 1,252 — Mark-to-market derivative liabilities 182 214 Unamortized energy contract liabilities 100 238 Renewable energy credit obligation 302 192 Other 356 413 Total current liabilities 4,933 4,459 Long-term debt 7,936 6,639 Long-term debt to affiliate 933 943 Deferred credits and other liabilities Deferred income taxes and unamortized investment tax credits 5,845 5,707 Asset retirement obligations 8,431 7,146 Non-pension postretirement benefit obligations 924 915 Spent nuclear fuel obligation 1,021 1,021 Payables to affiliates 2,577 2,880 Mark-to-market derivative liabilities 150 105 Unamortized energy contract liabilities 117 211 Payable for Zion Station decommissioning 90 155 Other 602 719 Total deferred credits and other liabilities 19,757 18,859 Total liabilities 33,559 30,900 Commitments and contingencies Contingently redeemable noncontrolling interests 28 — Equity Member’s equity Membership interest 8,997 8,951 Undistributed earnings 2,701 3,803 Accumulated other comprehensive income (loss), net (63) (36) Total member’s equity 11,635 12,718 Noncontrolling interest 1,307 1,333 Total equity 12,942 14,051 Total liabilities and equity $46,529 $44,951 (a)Generation’s consolidated assets include $8,235 million and $8,118 million at December 31, 2015 and 2014, respectively, of certain VIEs that can only be used to settle theliabilities of the VIE. Generation’s consolidated liabilities include $3,135 million and $2,512 million at December 31, 2015 and 2014, respectively, of certain VIEs for which the VIEcreditors do not have recourse to Generation. See Note 2–Variable Interest Entities. See the Combined Notes to Consolidated Financial Statements 210(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2012 $8,876 $3,168 $513 $108 $12,665 Net income (loss) — 1,070 — (10) 1,060 Distribution to member — (625) — — (625) Allocation of tax benefit from member 26 — — — 26 Consolidated VIE dividend to noncontrollinginterest — — — (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 uponconsolidation of CENG — — — 1,548 1,548 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 — — (134) — (134) Balance, December 31, 2014 $8,951 $3,803 $(36) $1,333 $14,051 Net income (loss) — 1,372 — (32) 1,340 Acquisition of non-controlling interest (1) — — 2 1 Adjustment of contingently redeemablenoncontrolling interest due to release ofcontingency — — — 4 4 Allocation of tax benefit from member 47 — — — 47 Distribution to member — (2,474) — — (2,474) Other comprehensive loss, net of income taxes — — (27) — (27) Balance, December 31, 2015 $8,997 $2,701 $(63) $1,307 $12,942 See the Combined Notes to Consolidated Financial Statements 211Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Operating revenues Electric operating revenues $4,901 $4,560 $4,461 Operating revenues from affiliates 4 4 3 Total operating revenues 4,905 4,564 4,464 Operating expenses Purchased power 1,301 1,001 662 Purchased power from affiliate 18 176 512 Operating and maintenance 1,372 1,263 1,211 Operating and maintenance from affiliate 195 166 157 Depreciation and amortization 707 687 669 Taxes other than income 296 293 299 Total operating expenses 3,889 3,586 3,510 Gain on sales of assets 1 2 — Operating income 1,017 980 954 Other income and (deductions) Interest expense (319) (308) (566) Interest expense to affiliates, net (13) (13) (13) Other, net 21 17 26 Total other income and (deductions) (311) (304) (553) Income before income taxes 706 676 401 Income taxes 280 268 152 Net income $426 $408 $249 Comprehensive income $426 $408 $249 See the Combined Notes to Consolidated Financial Statements 213Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Cash flows from operating activities Net income $426 $408 $249 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 707 687 669 Deferred income taxes and amortization of investment tax credits 353 433 (57) Other non-cash operating activities 416 255 28 Changes in assets and liabilities: Accounts receivable (93) (121) (12) Receivables from and payables to affiliates, net (19) (11) (12) Inventories (40) (16) (18) Accounts payable and accrued expenses 68 95 91 Counterparty collateral received (posted), net and cash deposits (33) 2 53 Income taxes 192 (159) 178 Pension and non-pension postretirement benefit contributions (150) (248) (122) Other assets and liabilities 69 1 171 Net cash flows provided by operating activities 1,896 1,326 1,218 Cash flows from investing activities Capital expenditures (2,398) (1,689) (1,433) Proceeds from sales of investments — 7 7 Purchases of investments — (3) (4) Change in restricted cash 2 (2) (2) Other investing activities 34 32 45 Net cash flows used in investing activities (2,362) (1,655) (1,387) Cash flows from financing activities Changes in short-term borrowings (10) 120 184 Issuance of long-term debt 850 900 350 Retirement of long-term debt (260) (617) (252) Contributions from parent 202 273 — Dividends paid on common stock (299) (307) (220) Other financing activities (16) (10) (1) Net cash flows provided by financing activities 467 359 61 Increase (decrease) in cash and cash equivalents 1 30 (108) Cash and cash equivalents at beginning of period 66 36 144 Cash and cash equivalents at end of period $67 $66 $36 See the Combined Notes to Consolidated Financial Statements 214Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 ASSETS Current assets Cash and cash equivalents $67 $66 Restricted cash 2 4 Accounts receivable, net Customer 533 477 Other 272 648 Receivables from affiliates 199 14 Inventories, net 164 125 Regulatory assets 218 349 Other 63 40 Total current assets 1,518 1,723 Property, plant and equipment, net 17,502 15,793 Deferred debits and other assets Regulatory assets 895 852 Investments 6 6 Goodwill 2,625 2,625 Receivable from affiliates 2,172 2,571 Prepaid pension asset 1,490 1,551 Other 324 237 Total deferred debits and other assets 7,512 7,842 Total assets $26,532 $25,358 See the Combined Notes to Consolidated Financial Statements 215Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term borrowings $294 $304 Long-term debt due within one year 665 260 Accounts payable 660 598 Accrued expenses 706 331 Payables to affiliates 62 84 Customer deposits 131 128 Regulatory liabilities 155 125 Mark-to-market derivative liability 23 20 Other 70 73 Total current liabilities 2,766 1,923 Long-term debt 5,844 5,665 Long-term debt to financing trust 205 205 Deferred credits and other liabilities Deferred income taxes and unamortized investment tax credits 4,914 4,561 Asset retirement obligations 111 103 Non-pension postretirement benefits obligations 259 263 Regulatory liabilities 3,459 3,655 Mark-to-market derivative liability 224 187 Other 507 889 Total deferred credits and other liabilities 9,474 9,658 Total liabilities 18,289 17,451 Commitments and contingencies Shareholders’ equity Common stock 1,588 1,588 Other paid-in capital 5,677 5,468 Retained earnings 978 851 Total shareholders’ equity 8,243 7,907 Total liabilities and shareholders’ equity $26,532 $25,358 See the Combined Notes to Consolidated Financial Statements 216Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 TotalShareholders’Equity Balance, December 31, 2012 $1,588 $5,014 $(1,639) $2,360 $7,323 Net income — — 249 — 249 Common stock dividends — — — (220) (220) Parent tax matter indemnification — 176 — — 176 Appropriation of retained earnings for future dividends — — (249) 249 — Balance, Balance at December 31, 2013 $1,588 $5,190 $(1,639) $2,389 $7,528 Net income — — 408 — $408 Common stock dividends — — — (307) (307) Contribution from parent — 273 — — 273 Parent tax matter indemnification — 5 — — 5 Appropriation of retained earnings for future dividends — — (408) 408 — Balance, December 31, 2014 $1,588 $5,468 $(1,639) $2,490 $7,907 Net income — — 426 — 426 Common stock dividends — — — (299) (299) Contribution from parent — 202 — — 202 Parent tax matter indemnification — 7 — — 7 Appropriation of retained earnings for future dividends — — (426) 426 — Balance, December 31, 2015 $1,588 $5,677 $(1,639) $2,617 $8,243 See the Combined Notes to Consolidated Financial Statements 217Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Operating revenues Electric operating revenues $2,485 $2,446 $2,499 Natural gas operating revenues 545 646 600 Operating revenues from affiliates 2 2 1 Total operating revenues 3,032 3,094 3,100 Operating expenses Purchased power 735 740 612 Purchased fuel 235 327 296 Purchased power from affiliate 220 194 392 Operating and maintenance 684 767 647 Operating and maintenance from affiliates 110 99 101 Depreciation and amortization 260 236 228 Taxes other than income 160 159 158 Total operating expenses 2,404 2,522 2,434 Gain on sales of assets 2 — — Operating income 630 572 666 Other income and (deductions) Interest expense (102) (101) (103) Interest expense to affiliates, net (12) (12) (12) Other, net 5 7 6 Total other income and (deductions) (109) (106) (109) Income before income taxes 521 466 557 Income taxes 143 114 162 Net income 378 352 395 Preferred security dividends and redemption — — 7 Net income attributable to common shareholder $378 $352 $388 Comprehensive income $378 $352 $395 See the Combined Notes to Consolidated Financial Statements 219Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Cash flows from operating activities Net income $378 $352 $395 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 260 236 228 Deferred income taxes and amortization of investment tax credits 90 88 20 Other non-cash operating activities 70 92 108 Changes in assets and liabilities: Accounts receivable 37 (16) (79) Receivables from and payables to affiliates, net 3 (6) (18) Inventories 10 2 2 Accounts payable and accrued expenses (25) 58 31 Income taxes (9) (57) 87 Pension and non-pension postretirement benefit contributions (40) (16) (31) Other assets and liabilities (4) (21) 4 Net cash flows provided by operating activities 770 712 747 Cash flows from investing activities Capital expenditures (601) (661) (537) Change in restricted cash (1) — (2) Other investing activities 14 12 8 Net cash flows used in investing activities (588) (649) (531) Cash flows from financing activities Payment of accounts receivable agreement — — (210) Issuance of long-term debt 350 300 550 Retirement of long-term debt — (250) (300) Contributions from parent 16 24 27 Dividends paid on common stock (279) (320) (332) Dividends paid on preferred securities — — (1) Redemption of preferred securities — — (93) Other financing activities (4) (4) (2) Net cash flows provided by (used in) financing activities 83 (250) (361) Increase (decrease) in cash and cash equivalents 265 (187) (145) Cash and cash equivalents at beginning of period 30 217 362 Cash and cash equivalents at end of period $295 $30 $217 See the Combined Notes to Consolidated Financial Statements 220Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 ASSETS Current assets Cash and cash equivalents $295 $30 Restricted cash and cash equivalents 3 2 Accounts receivable, net Customer 258 320 Other 146 141 Receivables from affiliates 2 3 Inventories, net Fossil fuel 43 57 Materials and supplies 26 22 Prepaid utility taxes 11 10 Regulatory assets 34 29 Other 24 31 Total current assets 842 645 Property, plant and equipment, net 7,141 6,801 Deferred debits and other assets Regulatory assets 1,583 1,529 Investments 28 31 Receivable from affiliates 405 490 Prepaid pension asset 347 344 Other 21 20 Total deferred debits and other assets 2,384 2,414 Total assets $10,367 $9,860 See the Combined Notes to Consolidated Financial Statements 221Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 LIABILITIES AND SHAREHOLDER’S EQUITY Current liabilities Long-term debt due within one year $300 $— Accounts payable 281 337 Accrued expenses 109 91 Payables to affiliates 55 52 Customer deposits 58 52 Regulatory liabilities 112 90 Other 29 31 Total current liabilities 944 653 Long-term debt 2,280 2,232 Long-term debt to financing trusts 184 184 Deferred credits and other liabilities Deferred income taxes and unamortized investment tax credits 2,792 2,602 Asset retirement obligations 27 29 Non-pension postretirement benefits obligations 287 287 Regulatory liabilities 527 657 Other 90 95 Total deferred credits and other liabilities 3,723 3,670 Total liabilities 7,131 6,739 Commitments and contingencies Shareholder’s equity Common stock 2,455 2,439 Retained earnings 780 681 Accumulated other comprehensive income, net 1 1 Total shareholder’s equity 3,236 3,121 Total liabilities and shareholder’s equity $10,367 $9,860 See the Combined Notes to Consolidated Financial Statements 222Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Shareholder’s Equity (In millions) CommonStock RetainedEarnings AccumulatedOtherComprehensiveIncome TotalShareholder’sEquity 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 Net income — 378 — 378 Common stock dividends — (279) — (279) Allocation of tax benefit from parent 16 — — 16 Balance, December 31, 2015 $2,455 $780 $1 $3,236 See the Combined Notes to Consolidated Financial Statements 223Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Operating revenues Electric operating revenues $2,490 $2,460 $2,405 Natural gas operating revenues 631 680 647 Operating revenues from affiliates 14 25 13 Total operating revenues 3,135 3,165 3,065 Operating expenses Purchased power 602 733 676 Purchased fuel 205 302 293 Purchased power from affiliate 498 382 452 Operating and maintenance 565 614 551 Operating and maintenance from affiliates 118 103 83 Depreciation and amortization 366 371 348 Taxes other than income 224 221 213 Total operating expenses 2,578 2,726 2,616 Gain on sales of assets 1 — — Operating income 558 439 449 Other income and (deductions) Interest expense (83) (90) (106) Interest expense to affiliates, net (16) (16) (16) Other, net 18 18 17 Total other income and (deductions) (81) (88) (105) Income before income taxes 477 351 344 Income taxes 189 140 134 Net income 288 211 210 Preference stock dividends 13 13 13 Net income attributable to common shareholder $275 $198 $197 Comprehensive income $288 $211 $210 See the Combined Notes to Consolidated Financial Statements 225Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Cash flows from operating activities Net income $288 $211 $210 Adjustments to reconcile net income to net cash flows provided by operating activities: Depreciation, amortization and accretion 366 371 348 Deferred income taxes and amortization of investment tax credits 165 116 125 Other non-cash operating activities 137 180 153 Changes in assets and liabilities: Accounts receivable 84 46 (127) Receivables from and payables to affiliates, net (2) (1) (14) Inventories 18 (6) 1 Accounts payable, accrued expenses (3) (75) (6) Collateral received (posted), net (27) 27 — Income taxes (54) 45 (33) Pension and non-pension postretirement benefit contributions (17) (16) (24) Other assets and liabilities (173) (158) (72) Net cash flows provided by operating activities 782 740 561 Cash flows from investing activities Capital expenditures (719) (620) (587) Change in restricted cash 26 (22) 2 Other investing activities 18 20 14 Net cash flows used in investing activities (675) (622) (571) Cash flows from financing activities Changes in short-term borrowings 90 (15) 135 Issuance of long-term debt — — 300 Retirement of long-term debt (75) (70) (467) Dividends paid on common stock (158) — — Dividends paid on preference stock (13) (13) (13) Allocations of tax benefit from parent 7 — — Other financing activities (13) 13 (3) Net cash flows used in financing activities (162) (85) (48) Increase (decrease) in cash and cash equivalents (55) 33 (58) Cash and cash equivalents at beginning of period 64 31 89 Cash and cash equivalents at end of period $9 $64 $31 See the Combined Notes to Consolidated Financial Statements 226Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 ASSETS Current assets Cash and cash equivalents $9 $64 Restricted cash and cash equivalents 24 50 Accounts receivable, net Customer 300 390 Other 112 82 Inventories, net Gas held in storage 36 57 Materials and supplies 33 30 Prepaid utility taxes 61 59 Regulatory assets 267 214 Other 3 5 Total current assets 845 951 Property, plant and equipment, net 6,597 6,204 Deferred debits and other assets Regulatory assets 514 510 Investments 12 12 Prepaid pension asset 319 370 Other 8 9 Total deferred debits and other assets 853 901 Total assets $8,295 $8,056 See the Combined Notes to Consolidated Financial Statements 227 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term borrowings $210 $120 Long-term debt due within one year 378 75 Accounts payable 209 215 Accrued expenses 110 131 Payables to affiliates 52 66 Customer deposits 102 92 Regulatory liabilities 38 44 Other 35 51 Total current liabilities 1,134 794 Long-term debt 1,480 1,857 Long-term debt to financing trust 252 252 Deferred credits and other liabilities Deferred income taxes and unamortized investment tax credits 2,081 1,911 Asset retirement obligations 17 17 Non-pension postretirement benefits obligations 209 212 Regulatory liabilities 184 200 Other 61 60 Total deferred credits and other liabilities 2,552 2,400 Total liabilities 5,418 5,303 Commitments and contingencies Shareholders’ equity Common stock 1,367 1,360 Retained earnings 1,320 1,203 Total shareholders’ equity 2,687 2,563 Preference stock not subject to mandatory redemption 190 190 Total equity 2,877 2,753 Total liabilities and shareholders’ equity $8,295 $8,056 (a)BGE’s consolidated assets include $26 million and $24 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used tosettle the liabilities of the VIE. BGE’s consolidated liabilities include $122 million and $197 million at December 31, 2015 and December 31, 2014, 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 228 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Preferencestocknot subject tomandatoryredemption TotalEquity 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 Net income — 288 288 — 288 Preference stock dividends — (13) (13) — (13) Common stock dividends — (158) (158) — (158) Contribution from parent 7 — 7 — 7 Balance, December 31, 2015 $1,367 $1,320 $2,687 $190 $2,877 See the Combined Notes to Consolidated Financial Statements 229Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 26 27 Exelon Corporation • • • • • • • • • • • • • • • • • • • • • • • • • • • Exelon Generation Company, LLC • • • • • • • • • • • • • • • • • • • • • • • • • Commonwealth Edison Company • • • • • • • • • • • • • • • • • • • PECO Energy Company • • • • • • • • • • • • • • • • • • • • • Baltimore Gas And Electric Company • • • • • • • • • • • • • • • • • • • 1. Significant Accounting Policies (Exelon, Generation, ComEd, PECO and BGE) Description of Business (Exelon, Generation, ComEd, PECO and BGE) Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy deliverybusinesses. On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As aresult, Exelon and Generation consolidated CENG’s financial position and results of operations into their businesses. Prior to April 1, 2014, Exelonand Generation accounted for CENG as an equity method investment. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLCfor further information regarding the integration transaction. The energy generation business includes: • Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and 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 Power 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. 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 230Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) indicated above in the Index to Combined Notes to Consolidated Financial Statements and parenthetically next to each corresponding disclosure.When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions havebeen eliminated. As a result of the Registrants’ 2014 divestiture of certain unconsolidated affiliates considered integral to their operations and theconsolidation of CENG during 2014, all Equity in earnings (losses) from unconsolidated affiliates have been presented below Income taxes in theRegistrants’ Consolidated Statements of Operations and Comprehensive Income starting in the first quarter of 2015. 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, 2015 and December 31, 2014, 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 additional 12.5% 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, 2015 and December 31, 2014, as equity. 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 231Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelondoes not have a controlling financial interest in an entity, it applies proportionate consolidation, equity method accounting or cost methodaccounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share ofeach liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants andtransmission 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. Exelon revised the presentation on the Statements of Operations and Comprehensive Income for PECO and BGE to reflect separatelyoperating revenues from the sale of electricity and operating revenues from the sale of natural gas, as well as, purchased power expense andpurchased fuel expense within the operating expenses section of the Statement of Operations and Comprehensive Income. Further, Exelonrevised the presentation from total operating revenues to “Rate-regulated utility revenues” and “Competitive businesses revenues” on the face ofExelon’s consolidated Statement of Operations and Comprehensive Income for all periods presented. Similarly, Exelon will separately presentrate-regulated purchased power and fuel expense and non-rate regulated 232Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) purchased power and fuel expense on the face of Exelon’s consolidated Statement of Operations and Comprehensive Income for all periodspresented. The reclassifications described herein were made for presentation purposes and did not affect any of the Registrants’ total revenues ornet income. 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 that rates are set at levels that will recover the entities’ costs fromcustomers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from theregulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively,under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense orrevenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelonbelieves that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates.However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting forcertain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portionof ComEd’s, PECO’s or BGE’s business was no longer able to meet the criteria discussed above, the affected entities would be required toeliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their resultsof 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 andComprehensive Income, the classification of which depends on the net hourly activity. In addition, capacity revenue and expense classification isbased on the net sale or purchase position of the Company in the different RTOs and ISOs. 233Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 ComEd receives full cost recovery for energy procurement and related costs fromretail customers, ComEd records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset orliability on its Consolidated Balance Sheets. Refer to Note 3—Regulatory Matters and Note 13—Derivative Financial Instruments for furtherinformation. 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 13—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 15—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 234Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. SeeNote 24—Supplemental Financial Information for Generation’s, ComEd’s, PECO’s and BGE’s utility taxes that are presented on a gross basis. Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE) The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and 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, 2015and 2014, 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, 2015 and 2014, 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, 2015 and 2014, ComEd’srestricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As ofDecember 31, 2015 and 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgageindenture. As of December 31, 2015 and 2014, 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, 2015and 2014, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified asnoncurrent assets. As of December 31, 2015, 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, PECOand BGE estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for eachcompany to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar creditquality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates appliedto the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment.ComEd, PECO and BGE customers’ accounts are generally considered delinquent if the amount billed is not received by the time the next bill isissued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent with approved regulatoryrequirements. ComEd’s, PECO’s and BGE’s provisions for uncollectible accounts will continue to be affected by changes in volume, prices andeconomic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3—Regulatory Matters for additionalinformation regarding the regulatory recovery of uncollectible accounts receivable at ComEd. 235Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 and oil. The costs of natural gas,propane 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. Marketable Securities (Exelon, Generation, ComEd, PECO and BGE) All marketable securities are reported at fair value. Marketable securities held in the NDT funds are classified as trading securities and allother securities are classified as available-for-sale securities. 236Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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. Unrealized gains and losses, net of tax, for Exelon’s available-for-sale securities are reported in OCI. Any decline in the fair value of Exelon’s available-for-sale securities below the cost basis is reviewed todetermine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-salesecurities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 16—AssetRetirement Obligations for information regarding marketable securities held by NDT funds and Note 24—Supplemental Financial Information foradditional information regarding ComEd’s and PECO’s regulatory assets and liabilities. Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. ComEd,PECO and BGE also include indirect construction costs including labor and related costs of departments associated with supporting 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 havebeen accounted 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. 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. 237Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 7—Property, Plant and Equipment, Note 10—Jointly Owned Electric Utility Plant and Note 24—Supplemental Financial Informationfor additional information regarding property, plant and equipment. Nuclear Fuel (Exelon and Generation) The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method.Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was 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 23—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. New site development costs incurred prior to a project’s completion being deemed probable are expensed as incurred.Approximately $22 million, $13 million and $10 million of costs were expensed by Exelon and Generation for the years ended December 31, 2015,2014, and 2013, respectively. These costs are related to the possible development of new power generating facilities. 238Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 within property, plant, and equipment. Such capitalized amounts are amortized ratably over the expected lives of the projects whenthey become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives basedon the expected life or pursuant to prescribed regulatory requirements. The following table presents net unamortized capitalized software costs andamortization of capitalized software costs by year: Net unamortized software costs Exelon Generation ComEd PECO BGE December 31, 2015 $633 $180 $172 $86 $178 December 31, 2014 596 193 133 84 163 Amortization of capitalized software costs Exelon Generation ComEd PECO BGE 2015 $208 $73 $47 $33 $46 2014 186 59 45 28 43 2013 198 67 52 33 36 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 have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.Amortization of ComEd’s distribution formula rate regulatory asset and ComEd’s and BGE’s transmission formula rate regulatory assets isrecorded to Operating revenues. 239Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of theregulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded toDepreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 3—Regulatory Matters and Note 24—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 unless circumstances warrant more frequent updates (such as a change in assumed operating life for a nuclearplant). As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previouslyassumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROsacross the nuclear fleet outside of the normal five-year rotating cost study update cycle. The liabilities associated with Exelon’s non-nuclear AROsare adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage ofnew laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalationfactors. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge toOperating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income or, in the case of the majority ofComEd’s, PECO’s, and BGE’s accretion, through an increase to regulatory assets. See Note 16—Asset Retirement Obligations for additionalinformation. 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. 240Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015 Total incurred interest $1,170 $445 $336 $116 $113 Capitalized interest 79 79 — — — Credits to AFUDC debt and equity 44 — 9 7 28 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 (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)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 byissuing 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 23—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, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of along-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired bycomparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-livedasset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of thelong-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 from related intangible assets andliabilities on the balance sheet. In certain cases, generating assets 241 (a) (a)(b)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independentof 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 Note11—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. Debt and Equity Security Investments. Exelon and Generation regularly monitor and evaluate debt and equity investments to determinewhether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary innature. 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. 242Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 through March 31, 2015. The effect of this decision is that allderivatives executed to hedge economic risk related to commodities are recorded at fair value with changes in fair value recognized throughearnings for the combined company. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of 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 13—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. 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 17—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 within their Consolidated Statements of Operations and Comprehensive Income. Equity inearnings (losses) of unconsolidated affiliates also includes any adjustments to amortize the difference, if any, except for goodwill and land,between their cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment. Exelon and Generation continuously monitor for issues that potentially could impact future profitability of these equity method investmentsand which could result in the recognition of an impairment loss if such investment experiences an other-than-temporary decline in value. New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE) Exelon has identified the following new accounting standards that have been recently adopted that management believes may significantlyaffect the Registrants. 243Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued authoritative guidance that requires deferred tax assets and deferred tax liabilities to be classified asnoncurrent in a classified statement of financial position. The guidance is effective for periods beginning after December 15, 2016, with earlyadoption permitted. The guidance can be applied either prospectively or retrospectively. The Registrants early adopted the standard retrospectivelyin the fourth quarter of 2015, resulting in the following impacts as of December 31, 2014 in the Consolidated Balance Sheets of the Registrants: For the year ended December 31, 2014 Exelon Generation ComEd PECO BGE Increase (Decrease) Current assets—Deferred income taxes $(244) $(327) $— $(69) $(6) Deferred debits and other assets—Other 3 — — — — Current liabilities—Deferred income taxes — — (63) — (52) Deferred credits and other liabilities—Deferred income taxes (241) (327) 63 (69) 46 The adoption of this guidance had no impact on the Registrants’ Consolidated Statements of Operations and Comprehensive Income andConsolidated Statements of Cash Flows. Simplifying the Accounting for Measurement-Period Adjustments In September 2015, the FASB issued authoritative guidance that requires an acquirer in a business combination to recognize adjustments toprovisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined andto record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, ifany, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Undercurrent guidance, such effects would be retrospectively recorded in prior periods. The guidance is effective for periods beginning afterDecember 15, 2015. The guidance is required to be applied prospectively to adjustments to provisional amounts that occur after the effective datewith earlier application permitted for financial statements that have not been issued. The Registrants early adopted the standard in the fourthquarter of 2015. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements ofOperations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. Application of Normal Purchases Normal Sales Exception to Power Contracts in Nodal Energy Markets In August 2015, the FASB issued authoritative guidance addressing the ability of entities to elect the normal purchase normal sales (NPNS)scope exception when the contract for the purchase or sale of electricity on a forward basis is delivered to a nodal energy market or transmittedthrough a nodal energy market. The NPNS scope exception allows entities to treat certain contracts that qualify as derivatives as contracts that donot require recognition at fair value. The guidance specifies that the use of locational marginal pricing by an independent system operator in suchtransactions does not constitute net settlement of a contract for the purchase or sale of electricity, even in scenarios in which legal title to theassociated electricity is conveyed to the independent system operator during transmission. Consequently, the use of locational marginal pricing bythe independent system operator does not cause that contract to fail to meet the physical delivery criterion of the NPNS scope exception.Consistent with the Registrants’ current practice, if the physical delivery criterion is met, along with all of the other criteria of the NPNS scopeexception, an entity may elect to designate that contract as 244Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) NPNS. The guidance is effective upon issuance and should be applied prospectively. The adoption of this guidance had no impact on theRegistrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of CashFlows and disclosures. Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued authoritative guidance that changes the presentation of debt issuance costs in financial statements. The newguidance requires entities to present such costs in the balance sheet as a direct reduction to the related debt liability rather than as a deferred cost(i.e., an asset) as required by current guidance. The new guidance does not change the recognition or measurement of debt issuance costs. Theguidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statementsthat have not been previously issued. The guidance is required to be applied retrospectively to all prior periods presented. The Registrants earlyadopted the standard retrospectively in the fourth quarter of 2015. The adoption of this guidance resulted in a reclassification of $157 million, $70million, $34 million, $14 million, and $16 million as of December 31, 2014, from Other long-term assets to Long-term debt, including Long-term debtto financing trusts, in the Consolidated Balance Sheets of Exelon, Generation, ComEd, PECO and BGE, respectively. The standard did not impactthe Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows of the Registrants. In August 2015, the FASB issued clarifying authoritative guidance for debt issuance costs incurred in connection with line-of-creditarrangements. The guidance states that an entity should defer and present debt issuance costs as an asset and subsequently amortize thedeferred debt issuance costs ratably over the term of the line-of-credit arrangement. The adoption of this guidance had no impact on theRegistrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of CashFlows and disclosures. The following recently issued accounting standards are not yet required to be reflected in the combined financial statements of theRegistrants. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued authoritative guidance which (i) requires all investments in equity securities, including other ownershipinterests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income,(ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for whichthe fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used toestimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and (iv) requires disclosure of thefair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transferthe liability. The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required tobe applied retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption(modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated BalanceSheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well asthe potential to early adopt the guidance. 245Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Simplifying the Measurement of Inventory In July 2015, the FASB issued authoritative guidance that requires inventory to be measured at the lower of cost or net realizable value. Thenew guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs ofcompletion, disposal and transportation. This definition is consistent with existing authoritative guidance. Current guidance requires inventory to bemeasured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less anapproximately normal profit margin. The guidance is effective for periods beginning after December 15, 2016 with early adoption permitted. Theguidance is required to be applied prospectively. The Registrants do not expect that this guidance will have a significant impact on theirConsolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows anddisclosures. The Registrants are currently assessing the potential to early adopt the guidance. Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share In May 2015, FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investmentsfor which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share usingthe practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on thestatement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to bemeasured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which theentity has elected to measure the fair value using the practical expedient. The guidance is effective for the Registrants for fiscal years beginningafter December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all prior periods presented. TheRegistrants are currently assessing the impacts this guidance may have on their disclosures. There will be no impact to the Registrants’Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows. Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer wouldaccount for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) thecustomer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it isfeasible for the customer to either run the software on its own hardware or contract with another party unrelated to the vendor to host the software.If the arrangement does not contain a software license, it would be accounted for as a service contract. Beginning January 1, 2016, theRegistrants will apply the standard prospectively and do not expect that this guidance will have a significant impact on their Consolidated BalanceSheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. Amendments to the Consolidation Analysis In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as wellas voting interest entities. The new guidance primarily (1) changes the assessment of limited partnerships as VIEs, (2) amends the effect thatfees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by 246Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (asa group) have power over an entity, and (5) provides a scope exception for registered and similar unregistered money market funds. The guidanceis effective for the Registrants for the first interim period beginning on or after December 15, 2015. The guidance can be applied retrospectively toeach prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings forinitial application of the guidance at the date of adoption (modified retrospective method). The Registrants are in the process of evaluating thestandard and have not identified any changes to consolidation conclusions as a result of the new guidance and therefore have not elected anadoption method. Based on the analysis completed to date, a limited number of additional entities will be considered variable interest entities whenthe guidance is adopted, and required disclosures will be included in the Variable Interest Entities footnote. 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 standard 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 can be applied retrospectively to each prior reporting periodpresented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of theguidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance mayhave on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements ofCash Flows and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the newguidance on our ability to recognize revenue for certain contracts where collectability is in question, our accounting for contributions in aid ofconstruction, bundled sales contracts and contracts with pricing provisions that may require us to recognize revenue at prices other than thecontract price (e.g., straight line or forward curve). In addition, the Registrants will be required to capitalize costs to acquire new contracts,whereas Exelon currently expenses those costs as incurred. In August 2015, the FASB issued an amendment to provide a one year deferral of theeffective date to annual reporting periods beginning on or after December 15, 2017, as well as an option to early adopt the standard for annualperiods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard. 2. Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities,equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to theirownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returnsof the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to directthe activities that most significantly affect the entity’s economic performance. 247Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014, Exelon, Generation, and BGE collectively consolidated seven and six VIEs or VIE groups, respectively, forwhich the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of December 31, 2015 and2014, the Registrants had significant interests in eight and six other VIEs, respectively, for which the Registrants do not have the power to directthe entities’ activities and, accordingly, were not the primary beneficiary (see Unconsolidated Variable Interest Entities below). 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, 2015 and 2014 are as follows: December 31, 2015 December 31, 2014 Exelon Generation BGE Exelon Generation BGE Current assets $909 $881 $23 $1,275 $1,247 $21 Noncurrent assets 8,009 8,004 3 7,573 7,560 3 Total assets $8,918 $8,885 $26 $8,848 $8,807 $24 Current liabilities $473 $387 $81 $611 $526 $77 Noncurrent liabilities 2,927 2,884 41 2,728 2,597 120 Total liabilities $3,400 $3,271 $122 $3,339 $3,123 $197 (a)Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to classification of deferred taxes and simplifying the presentation ofdebt costs. See Note 1—Significant Accounting Policies for additional information.(b)Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. 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’s, Generation’s 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. 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 2015, 2014, and 2013, BGE remitted $86 million, $85 million, and $83million, respectively, to BondCo. BGE did not provide any additional financial support to BondCo during 2015. 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. 248(a)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 can makeany 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, Generation acquired all of the equity interests in Antelope Valley Solar Ranch One (Antelope Valley)from First Solar, Inc., a 242-MW solar PV project in northern Los Angeles County, California. In addition, Generation owns a number of limitedliability companies that build, own, and operate solar power facilities. While Generation owns 100% of these entities, it has been determined thatcertain of the individual solar project entities are VIEs because the entities require additional subordinated financial support in the form of aparental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or thecustomers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primarybeneficiary of the solar project entities that qualify as VIEs because Generation controls the design, construction, and operation of the solar powerfacilities. Generation provides operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solarpower facilities and provides limited recourse related to the Antelope Valley project. In addition, these solar VIE entities have an aggregate amountof outstanding debt with third parties of $655 million, as of December 31, 2015, for which the creditors have no recourse to Generation. Foradditional information on these project-specific financing arrangements refer to Note 14—Debt and Credit Agreements. Retail Power and Gas Companies. In March 2014, Generation began consolidating retail power and gas VIEs for which Generation is theprimary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect theeconomic performance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $12million in credit support for the retail power and gas companies. These entities are included in Generation’s consolidated financial statements, andthe consolidation of the VIEs do 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 during 2010 with the acquisition of all of the equity 249Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) interests of John Deere Renewables, LLC (now known as Exelon Wind). Generation has evaluated the significant agreements and ownershipstructures and the risks of each of its wind projects and underlying entities, and determined that certain of the entities are VIEs because either theprojects have noncontrolling equity interest holders that absorb variability from the wind projects, or the customers absorb price variability from theentities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the wind project entities thatqualify as VIEs because Generation controls the design, construction, and operation of the wind generation facilities. While Generation owns 100%of the majority of the wind project entities, nine of the projects have noncontrolling equity interests of 1% held by third parties. Generation’s currenteconomic interests in eight of these projects is significantly greater than its stated contractual governance rights and all of these projects havereversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargainpurchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon either the passage of time or theachievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation is to provide financialsupport to the projects in proportion to its current 99% economic interests in the projects. However, no additional support to these projects beyondwhat was contractually required has been provided during 2015. As of December 31, 2015, the carrying amount of the assets and liabilities that areconsolidated as a result of Generation being the primary beneficiary of the wind VIE entities primarily relates to the wind generating assets, PPAintangible assets and working capital amounts. Other Generating Facilities. During the second quarter of 2015, Generation formed a limited liability company to build, own, and operate abackup generator. While Generation owns 100% of the backup generator company, it was determined that the entity is a VIE because thecustomer absorbs price variability from the entity through the fixed price backup generator agreement. Generation provides operating and capitalfunding to the backup generator company. Generation also owns 90% of a biomass fueled, combined heat and power company. In the secondquarter of 2015, the entity was deemed to be a VIE because the entity requires additional subordinated financial support in the form of a parentalguarantee provided by Generation for up to $275 million in support of the payment obligations related to the Engineering, Procurement andConstruction contract for the facility (see Note 14—Debt and Credit Agreements for additional details on Albany Green Energy, LLC). In addition tothe parental guarantee, Generation provides operating and capital funding to the biomass fueled, combined heat and power company. Generation isthe primary beneficiary of both entities since Generation has the power to direct the activities that most significantly affect the economicperformance of the entities. CENG. Through March 31, 2014, CENG was operated as a joint venture with EDF and was governed by a board of ten directors, five ofwhich were appointed by Generation and five by EDF. CENG was designed to operate under joint and equal control of Generation and EDF throughthe Board of Directors, subject to the Chairman of the Board’s final decision making authority on certain special matters; therefore, CENG was notsubject to VIE guidance. Accordingly, Generation’s 50.01% interest in CENG was accounted for as an equity method investment. On April 1,2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generationnow conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and theCENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG memberrights of EDF. As a result of executing the NOSA, CENG now qualifies as a VIE due to the disproportionate relationship between Generation’s50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA. 250Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)—(Continued) Further, since Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary ofCENG and, 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 EDF 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 5—Investment in Constellation Energy NuclearGroup, LLC and Note 26—Related Party Transactions 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 EDF, • 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 or will purchase 50.01% of the available output generated by theCENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of eachrespective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant(Ginna) PPAs have been suspended during the term of the expected Reliability Support Services Agreement (RSSA). (see Note 3—Regulatory Matters for additional details), • Generation provided a $400 million loan to CENG. As of December 31, 2015, the remaining obligation is $300 million including accruedinterest, which reflects the principal payment made in January 2015 (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 against third-party claims thatmay arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or theiroperations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 23—Commitments andContingencies 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 in 2014 through 2016. As of December 31, 2015, the remaining obligation is approximately $1million, • Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premiumadjustments for the nuclear liability insurance (See Note 23—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, EDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of anyamounts paid by Generation under this guarantee, 251Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 EDF 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 23—Commitments and Contingencies for more details), and • 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, 2015 and 2014, ComEd and PECO did not have any material consolidated VIEs. 252Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settleobligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As ofDecember 31, 2015 and 2014, these assets and liabilities primarily consisted of the following: December 31, 2015 December 31, 2014 Exelon Generation BGE Exelon Generation BGE Cash and cash equivalents $164 $164 $— $392 $392 $— Restricted cash 100 77 23 117 96 21 Accounts receivable, net Customer 219 219 — 297 297 — Other 43 43 — 57 57 — Mark-to-market derivatives assets 140 140 — 171 171 — Inventory Materials and supplies 181 181 — 172 172 — Other current assets 35 30 — 37 30 — Total current assets 882 854 23 1,243 1,215 21 Property, plant and equipment, net 5,160 5,160 — 4,638 4,638 — Nuclear decommissioning trust funds 2,036 2,036 — 2,097 2,097 — Goodwill 47 47 — 47 47 — Mark-to-market derivatives assets 53 53 — 44 44 — Other noncurrent assets 90 85 3 90 77 3 Total noncurrent assets 7,386 7,381 3 6,916 6,903 3 Total assets $8,268 $8,235 $26 $8,159 $8,118 $24 Long-term debt due within one year $111 $27 $79 $87 $5 $75 Accounts payable 216 216 — 292 292 — Accrued expenses 115 113 2 111 108 2 Mark-to-market derivative liabilities 5 5 — 24 24 — Unamortized energy contract liabilities 12 12 — 22 22 — Other current liabilities 13 13 — 25 25 — Total current liabilities 472 386 81 561 476 77 Long-term debt 666 623 41 212 81 120 Asset retirement obligations 1,999 1,999 — 1,763 1,763 — Pension obligation 9 9 — 9 9 — Unamortized energy contract liabilities 39 39 — 51 51 — Other noncurrent liabilities 79 79 — 132 132 — Noncurrent liabilities 2,792 2,749 41 2,167 2,036 120 Total liabilities $3,264 $3,135 $122 $2,728 $2,512 $197 (a)Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to classification of deferred taxes and simplifying the presentation ofdebt costs. See Note 1- Significant Accounting Policies for additional information.(b)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 Note17—Retirement Benefits for additional details. 253(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 of the investments is reflected on Exelon’s and Generation’s Consolidated BalanceSheets in Investments. For the energy purchase and sale contracts (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, 2015 and 2014, Exelon and Generation had significant unconsolidated variable interests in eight and six VIEs,respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments andcertain commercial agreements. The increase in the number of unconsolidated VIEs is due to the execution of an energy purchase and saleagreement with a new unconsolidated VIE and an equity investment in a new unconsolidated VIE. The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities: December 31, 2015 CommercialAgreementVIEs EquityInvestmentVIEs Total Total assets $263 $164 $427 Total liabilities 22 125 147 Exelon’s ownership interest in VIE — 11 11 Other ownership interests in VIE 241 28 269 Registrants’ maximum exposure to loss: Carrying amount of equity method investments — 21 21 Contract intangible asset 9 — 9 Debt and payment guarantees — 3 3 Net assets pledged for Zion Station decommissioning 17 — 17 December 31, 2014 CommercialAgreementVIEs EquityInvestmentVIEs Total Total assets $114 $91 $205 Total liabilities 3 49 52 Exelon’s ownership interest in VIE — 9 9 Other ownership interests in VIE 111 33 144 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 (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. Exelon corrected an error in the December 31, 2014 balances within Commercial Agreement VIEs for anoverstatement of Total assets, Total liabilities and Other ownership interests in VIE of $392 million, $234 million and $158 million, respectively. The error is not considered materialto any prior period. 254 (a) (a) (a) (a) (b) (a) (a) (a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) (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 $206 million and $319 million as of December 31, 2015 and December 31, 2014, respectively; offset bypayables to ZionSolutions LLC of $189 million and $292 million as of December 31, 2015 and December 31, 2014, respectively. These items are included to provide informationregarding the relative size of the ZionSolutions LLC unconsolidated VIE. 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. 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 16—Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assetsand liabilities back to Generation when decommissioning activities under the asset sale agreement are complete. Generation has evaluated thisagreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result,Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon and Generation do not have anycontractual or other obligations to provide additional financial support and ZionSolutions’ creditors do not have any recourse to Exelon’s orGeneration’s general credit. Investment in Energy Development Projects, Distributed Energy Companies, and Energy Generating Facilities. Generation hasseveral equity investments in energy development projects and energy generating facilities. Generation has evaluated the significant agreements,ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because the entity has aninsufficient amount of equity at risk to finance its activities, Generation guarantees the debt of the entity, provides equity support, or providesoperating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of theentities that qualify as VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economicperformance. In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energycompany. Generation’s total equity commitment in this arrangement was $91 million and is paid incrementally over an approximate two year period(see Note 23—Commitments and Contingencies for additional details). This arrangement did not meet the definition of a VIE and is recorded as anequity method investment. In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90%equity interest and 99% of the tax attributes of another distributed energy company. Separate from the equity investment, Generation provided $27million in cash to the other (10%) equity holder in the distributed energy company in exchange for a convertible 255Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) promissory note. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation andthe tax equity investor will contribute $250 million of equity incrementally through December 2016 in proportion to their ownership interests, whichequates to approximately $172 million for the tax equity investor and $78 million for Generation (see Note 23—Commitments and Contingencies foradditional details). Generation and the tax equity investor provide a parental guarantee of up to $275 million in proportion to their ownershipinterests in support of 2015 ESA Investco, LLC’s obligation to make equity contributions to the distributed energy company. The investment in thedistributed energy company was evaluated and it was determined to be a VIE for which Generation is not the primary beneficiary. Generationcontinues to consolidate 2015 ESA Investco, LLC under the voting interest model. Both distributed energy companies from the 2014 and 2015 arrangements are considered related parties. 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 14—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 electric distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA alsoprovides a structure for substantial capital investment by utilities to modernize Illinois’ electric utility infrastructure. EIMA was scheduled tosunset, ending ComEd’s performance based rate formula and investment commitment, at December 31, 2017, unless approved to continuethrough 2022 by the Illinois General Assembly. On April 3, 2015, the Governor signed legislation extending the EIMA sunset from 2017 to 2019. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rateseffective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capitaladditions (initial revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year andactual costs incurred for that year (annual reconciliation). See Annual Electric Distribution Filings below for further details. Throughout each year,ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to 256Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 revenue for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expectedto be approved by the ICC for that year’s reconciliation. As of December 31, 2015, and December 31, 2014, ComEd had a regulatory assetassociated with the electric distribution formula rate of $189 million and $371 million, respectively. The regulatory asset associated with electricdistribution true-up is amortized to Operating revenue in ComEd’s Consolidated Statement of Operations and Comprehensive Income as theassociated amounts are recovered through rates. Participating utilities are also required to file an annual update on their AMI implementation progress. On April 1, 2015, ComEd filed anannual progress report on its AMI Implementation Plan with the ICC, which allows for the installation of more than four million smart metersthroughout ComEd’s service territory by 2018. To date, approximately two million smart meters have been installed in the Chicago area. Pursuant to EIMA, ComEd annually contributes $4 million for customer education for as long as the AMI Deployment Plan remains in effect.Additionally, ComEd contributes $10 million annually through 2016 to fund customer assistance programs for low-income customers, which will notbe recoverable through rates. Annual Electric Distribution Filings For each of the following years, the ICC approved the following total increases/(decreases) in ComEd’s electric distributions formula rate filings: Annual Distribution Filings 2015 2014 2013 ComEd’s requested total revenue requirement(decrease) increase $(50) $269 $353 Final ICC Order Initial revenue requirement increase $85 $160 $160 Annual reconciliation (decrease) increase (152) 72 181 Total revenue requirement (decrease) increase $(67) $232 $341 Allowed Return on Rate Base: Initial revenue requirement 7.05% 7.06% 6.94% Annual reconciliation 7.02% 7.04% 6.94% Allowed ROE: Initial revenue requirement 9.14% 9.25% 8.72% Annual reconciliation 9.09% 9.20% 8.72% Effective date of rates January 2016 January 2015 January 2014 (a)Includes a reduction of 5 basis points for a reliability performance metric penalty. 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 257(a)(a)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) taxes against the annual reconciliation balance in calculating interest, and the use of average rather than year-end rate base for determining anyROE collar adjustment. On November 26, 2013, the ICC issued its final order in the Investigation, rejecting two of the proposed changes butaccepting the proposed change to eliminate the income tax gross-up on the weighted average cost of capital used to calculate interest on theannual reconciliation balance. The accepted change became effective in January 2014, and reduced ComEd’s 2014 revenue by approximately $8million. This change had no financial statement impact on ComEd in 2013. ComEd and intervenors requested rehearing, however all rehearingrequests were denied by the ICC. ComEd and intervenors filed appeals with the Illinois Appellate Court. ComEd subsequently withdrew its appeal,but the Illinois Attorney General and the Citizens Utility Board continued to argue that the ICC had wrongly approved ComEd’s treatment ofaccumulated deferred income taxes (ADIT) relating to the annual reconciliation. On July 29, 2015, the Illinois Appellate Court rejected that appealand affirmed the ICC’s decision and its acceptance of ComEd’s treatment of ADIT. The period in which to file requests for further review hasexpired and that decision is final. 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. OnSeptember 14, 2014, the Illinois Supreme Court declined to hear that appeal. ComEd elected not to seek review by the United States SupremeCourt on the Federal law issues. Accordingly, the decision of the Illinois Appellate Court is considered final. 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. The costs incurred for the project prior to May 21, 2014 were immaterial.ComEd has acquired numerous easements across the project route through voluntary transactions. ComEd will seek to acquire the property rightson the remaining 28 parcels through condemnation proceedings in the circuit courts. ComEd began construction of the line during the secondquarter of 2015 with an in-service date expected in the second quarter of 2017. 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. As ofDecember 31, 2015, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through 2021. 258Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 is required to purchase an increasing percentage of the electricity for customer deliveries from renewable energy resources.Purchases by customers of electricity from competitive electric 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. ComEd enteredinto several 20-year contracts with unaffiliated suppliers in December 2010 regarding the procurement of long-term renewable energy andassociated RECs in order to meet its obligations under the Illinois’ RPS. All associated costs are recoverable from customers. 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. ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. Inaddition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGencontract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014. 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. On January 13, 2016, FutureGen informed the Illinois Supreme Court that it had ceased all development efforts on the FutureGen project andwould soon be seeking to terminate the FutureGen supply agreements. Accordingly, FutureGen requested that the court dismiss the proceeding asmoot. A decision from the Illinois Supreme Court dismissing the matter is expected in early 2016. In February 2016, FutureGen terminated itssourcing agreement with ComEd. As a result, ComEd is under no further obligation under this agreement. 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 259Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) incremental annual program energy savings requirement of 2% 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 toreduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject torate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval bythe ICC. In January 2014, the ICC approved ComEd’s third three-year Energy Efficiency and Demand Response Plan covering the period June2014 through May 2017. The plans are designed to meet Illinois’ energy efficiency and demand response goals through May 2017, includingreductions 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, 2015, 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. Pennsylvania Regulatory Matters 2015 Pennsylvania Electric Distribution Rate Case (Exelon and PECO). On March 27, 2015, PECO filed a petition with the PAPUCrequesting an increase of $190 million to its annual service revenues for electric delivery, which requested an ROE of 10.95%. On September 10,2015, PECO and interested parties filed with the PAPUC a petition for joint settlement for an increase of $127 million in annual distribution servicerevenue. No overall ROE was specified in the settlement. On December 17, 2015, the PAPUC approved the settlement of PECO’s electricdistribution rate case. The approved electric delivery rates became effective on January 1, 2016. The settlement includes approval of the In-Program Arrearage Forgiveness (“IPAF”) Program, which provides for forgiveness of a portion ofthe eligible arrearage balance of its low-income Customer Assistance Program (CAP) accounts receivable that will be determined as of programinception in October 2016. The forgiveness will be granted to the extent CAP customers remain current with payments. The Settlement guaranteesPECO’s recovery of two-thirds of the arrearage balance through a combination of customer payments and rate recovery, including through futurerates cases if necessary. The remaining one-third of the arrearage balance will be absorbed by PECO, of which a portion has already beenexpensed as bad debt for CAP customer’s accounts receivable balances. 260Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Although the actual arrearage balance is not defined until program inception, PECO believes that it can reasonably estimate certain CAPcustomer accounts receivable balances as of December 31, 2015 that will remain outstanding at program inception. Management determined itsbest estimate based on historical collectability information. As a result, a regulatory asset of $7 million, representing the previously incurred baddebt expense associated with the estimated eligible accounts receivable balances, was recorded on Exelon’s and PECO’s Consolidated BalanceSheets as of December 31, 2015. This estimate will be revisited on a quarterly basis through program inception. 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 settlements included a stipulation regarding how tax benefits related to the application of any new IRS guidance on repairs deductionmethodology are to be handled from a rate-making perspective. The settlements required that the expected cash benefit from the application ofany new guidance to tax years prior to 2011 be refunded to customers over a seven-year period. On August 19, 2011, the IRS issued RevenueProcedure 2011-43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECO adopted the safeharbor and elected a method change for the 2010 tax year. The total refund to customers for the tax cash benefit from the application of the safeharbor to costs incurred prior to 2010 was $171 million. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to executethe refund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return,which is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2012. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 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 is awaiting IRS guidance that will provide a safe harbor method of accounting for gas transmission and distributionproperty. 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. As agreed to in the 2010 distribution rate case settlements, these benefits were reflected in the determination of revenuerequirements in the 2015 electric distribution rate case discussed above and will be reflected in the next natural gas distribution rate case. SeeNote 15—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). Through PECO’s first two PAPUC approved DSP Programs, PECOprocured electric supply for its default electric customers through PAPUC approved competitive procurements. DSP I and DSP II expired onMay 31, 2013 and May 31, 2015, respectively. The second DSP Program included a number of retail market enhancements recommended by the PAPUC in its previously issued RetailMarkets Intermediate Work Plan Order. PECO was also directed 261Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) to submit a plan to allow its low-income CAP customers to purchase their generation supply from EGSs beginning in April 2014. In May 2013,PECO filed its CAP Shopping Plan with the PAPUC. By an 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 July 14, 2015, the Court issued opinions on theOCA and low-income advocacy group appeal. Specifically, the Court remanded the issue to the PAPUC with instructions that it approve a rulerevision to the PECO CAP Shopping Plan that would prohibit CAP customers from entering into contracts with an EGS that would impose earlycancellation/termination fees. The PAPUC has appealed the Court’s decision. PECO does not have information at this time as to what action itmay be required to take following remand to the PAPUC. On December 4, 2014, the PAPUC approved PECO’s third DSP Program. 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. Under the program, PECO is procuring electricsupply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and smalland medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning inJune 2016, the medium commercial class (101-500 kW) will move to spot market pricing. As of December 31, 2015, PECO entered into contractswith PAPUC-approved bidders, including Generation, resulting from the first two of its four scheduled procurements. Charges incurred for electricsupply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Consolidated Statement ofOperations and Comprehensive Income. On March 12, 2015, PECO settled the CAP Design with the Office of Consumer Advocates (OCA) and Low Income Advocates, and filed theproposed plan with the PAPUC on March 20, 2015. The program design changes the rate structure of PECO’s CAP to make the bills moreaffordable to customers enrolled in the assistance program. The CAP discounts continue to be recovered through PECO’s universal service fundcost. On July 8, 2015, the CAP Design was approved by the PAPUC. PECO plans to implement the program changes in October 2016. Smart Meter and Smart Grid Investments (Exelon and PECO). In April 2010, pursuant to Act 129 and the follow-on Implementation Orderof 2009, 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. PECO is currently in the second phase of the SMPIP and hasdeployed substantially all remaining smart meters as of December 31, 2015, for a total of 1.7 million smart meters. In total, PECO currentlyexpects to spend up to $589 million, excluding the cost of the original meters, on its smart meter infrastructure and approximately $155 million onsmart grid investments through final deployment of which $200 million has been funded by SGIG. As of December 31, 2015, PECO has spent$578 million and $155 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received.Recovery of smart meter costs will be reflected in base rates effective January 1, 2016. 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. On November 15, 2013, PECO filed its final compliance report with the PAPUC communicating PECO had met all Phase Ireduction targets. 262Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provided energy consumption reduction requirementsfor the second phase of Act 129’s EE&C program, which went into effect on June 1, 2013. Pursuant to the Phase II implementation order, PECOfiled its three-year EE&C Phase II Plan with the PAPUC on November 1, 2012. The plan set forth how PECO would reduce electric consumptionby at least 1,125,852 MWh in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads.The implementation order permitted PECO to apply any excess savings achieved during Phase I against its Phase II consumption reductiontargets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the totalconsumption reductions had to be through programs directed toward PECO’s public and low income sectors, respectively. If PECO failed toachieve the required reductions in consumption, it would have been subject to civil penalties of up to $20 million, which would not be recoverablefrom ratepayers. Act 129 mandates that the total cost of the plan may not exceed 2% of the electric company’s total annual revenue as ofDecember 31, 2006. On March 15, 2013 and February 28, 2014, PECO filed Petitions for Approval to amend its EE&C Phase II Plan to continue its DLC demandreduction program for mass market customers through May 31, 2014 and May 31, 2016, respectively. PECO proposed to fund the estimated $10million annual costs of the plan by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered throughPECO’s Energy Efficiency Plan surcharge along with other Phase II Plan costs. The PAPUC granted PECO’s Petitions on May 5, 2013 andApril 23, 2014, respectively. The PAPUC issued its Phase III EE&C implementation order on June 19, 2015, that provides energy consumption reduction requirements forthe third phase of Act 129’s EE&C program with a five-year term from June 1, 2016 through May 31, 2021. The order tentatively establishedPECO’s five-year cumulative consumption reduction target at 2,080,553 MWh. Pursuant to the Phase III implementation order, PECO filed its five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. ThePlan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for theperiod June 1, 2016 through May 31, 2021. PECO expects a final decision from the PAPUC on PECO’s EE&C Phase III Plan during the firstquarter of 2016. 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 from approximately 3.5% to 8%, and the requirement for Tier IIalternative energy resources ranges from 6.2% to 10%. The required compliance percentages incrementally increase each annual complianceperiod, which is from June 1 through May 31, until May 31, 2021. These Tier I and Tier II alternative energy resources include acceptable energysources as set forth in Act 129 and the AEPS Act. PECO continues to procure alternative energy credits through full requirements contracts and its existing long-term solar contracts to meetthe annual AEPS compliance requirements. All AEPS compliance costs are being recovered on a full and current basis from default servicecustomers through the GSA. 263Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 (OCMO) to continue its investigation, confirming that natural gas distribution companiesshould remain with the default service model for the time being and directing establishment of a working group to examine other competitiveissues. The OCMO has established a working group to review operation of the natural gas retail market and to consider potential recommendationson competitive issues. Pennsylvania Act 11 of 2012 (Exelon and PECO). In February 2012, Act 11 was signed into law, which provided the PAPUC authority toapprove the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred torepair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to aDSIC, the PAPUC’s implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by theCommission, which outlines how the utility is planning to increase its investment for repairing, improving or replacing aging infrastructure. On May 7, 2015, the PAPUC approved PECO’s modified natural gas LTIIP. In accordance with the approved LTIIP, PECO plans to spend$534 million through 2022 to further accelerate the replacement of existing gas mains and to relocate meters from indoors to outside in accordancewith recent PAPUC rulemaking. In addition, on March 20, 2015, PECO filed a petition with the PAPUC for approval of its gas DSIC mechanism forrecovery of gas LTIIP expenditures. On September 11, 2015, the PAPUC entered its Opinion and Order approving PECO’s petition for a gas DSIC. On March 27, 2015, PECO filed a petition with the PAPUC for approval of its proposed electric DSIC and LTIIP. In accordance with theLTIIP (System 2020 plan), PECO plans to spend $275 million over the next five years to modernize and storm-harden its electric distributionsystem, making it more 264Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) weather resistant and less vulnerable to damage. The DSIC will allow PECO the opportunity to recover the costs, subject to certain criteria,incurred to repair, improve or replace its electric distribution property between rate cases. On October 22, 2015, the PAPUC entered its Opinionand Order approving PECO’s proposed petition for its electric LTIIP and DSIC. Maryland Regulatory Matters 2015 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On November 6, 2015, and as amended on January 5, 2016,BGE filed for electric and gas base rate increases with the MDPSC, ultimately requesting an increase of $121 million and $79 million, respectively,of which $103 million and $37 million, respectively, is related to recovery of smart grid initiative costs. BGE requested a ROE for the electric andgas distribution rate case of 10.6% and 10.5%, respectively. The new electric and gas base rates are expected to take effect in June 2016. BGEis also proposing to recover an annual increase of approximately $30 million for Baltimore City conduit lease fees through a surcharge. BGEcannot predict how much of the requested increase the MDPSC will approve or if it will approve BGE’s request for a conduit fee surcharge. 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 for completion in 2014 as part of the ERI initiative. The ERIinitiative surcharge became effective June 1, 2014. On November 2, 2015, BGE filed a surcharge update including a true-up of cost estimatesincluded in the 2015 surcharge, along with its work plan and cost estimates for 2016, to be included in the 2016 surcharge. The MDPSCsubsequently approved BGE’s 2016 work plan and the 2016 surcharge. 265Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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. On October 26, 2015, the Circuit Court for Baltimore City issued an order affirming the MDPSC’s decision.However, on November 30, 2015, the residential consumer advocate filed an appeal of the Circuit Court’s decision with the Maryland Court ofSpecial Appeals. BGE cannot predict the outcome of this appeal. If the residential consumer advocate’s appeal is successful, BGE could recoverERI expenditures through other regulatory mechanisms. 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 funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs,depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system isimplemented. As of December 31, 2015 and December 31, 2014, BGE recorded a regulatory asset of $196 million and $128 million, respectively,representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of thesettlement in BGE’s 2014 electric and gas distribution rate case, the cost of the retired non-AMI meters will be amortized over 10 years. On February 26, 2014, the MDPSC issued an order authorizing BGE to impose a $75 upfront fee and an $11 recurring fee to customerselecting to opt-out of BGE’s smart meter installation program, effective the later of the first full billing cycle following July 1, 2014, or the AMIinstallation date in a customer’s community. The fees authorized by the order will be reviewed after an initial 12 to 18 month period. OnNovember 25, 2014, the MDPSC issued a decision approving BGE’s proposal to automatically enroll unresponsive customers into the opt-outprogram and to charge those customers opt-out fees after BGE has exhausted attempts to schedule a meter installation. On November 5, 2015,the MDPSC held a hearing to evaluate the $11 recurring monthly fee paid by opt-out customers. Effective with January 2016 bills, the monthlyrecurring fee was reduced to $5.50. As part of the 2015 electric and gas distribution rate case filed on November 6, 2015, BGE is seeking recovery of its smart grid initiativecosts. Of BGE’s requested $200 million, $140 million relates to the smart grid initiative. In support of its recovery of smart grid initiative costs,BGE provided evidence demonstrating that the benefits exceed the costs by a ratio of 2.3 to 1.0, on a nominal basis. 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. CPVsubsequently sought to extend that date. The initial term of the proposed contract is 20 years. The CfD mandates that BGE and the other utilitiespay (or receive) the difference between CPV’s contract prices and the revenues CPV receives for capacity and energy from clearing the unit in thePJM capacity market. The MDPSC’s order requires the three Maryland utilities to enter into a CfD in amounts proportionate to their relative SOSload. 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. 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 266Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) October 24, 2013, the U.S. District Court issued a judgment order finding that the MDPSC’s Order directing BGE and the two other Marylandutilities to enter into a CfD, which assures that CPV receives a guaranteed fixed price regardless of the price set by the federally regulatedwholesale market, violates the Supremacy Clause of the United States Constitution. On November 22, 2013, the MDPSC and CPV appealed theDistrict Court’s ruling to the United States Court of Appeals for the Fourth Circuit. The Fourth Circuit affirmed the District Court ruling in an opinionissued June 2, 2014. The MDPSC and CPV filed petitions for certiorari, seeking review of the case by the U.S. Supreme Court. On October 29,2015, the U.S. Supreme Court granted the petition to review the Fourth Circuit decision, and that appeal is now pending in the Supreme Court withoral argument scheduled for February 24, 2016. On February 9, 2011, a civil complaint was filed by Exelon and other unaffiliated parties in the United States District Court for the District ofNew Jersey, challenging a 2011 New Jersey law, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. On October 25, 2013, the U.S. District Court issued a judgment orderfinding that LCAPP violates the Supremacy Clause of the United States Constitution. CPV and New Jersey appealed the District Court’s ruling tothe United States Court of Appeals for the Third Circuit. On September 11, 2014, the Third Circuit affirmed the District Court’s ruling finding LCAPPunconstitutional. On November 26, 2014, CPV and New Jersey sought Supreme Court review of the Third Circuit decision. On October 29, 2015,the Supreme Court stayed the petition to review the Third Circuit case pending their review of the Fourth Circuit Maryland case described above. 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. That appeal has been stayed pending decision by the U.S. Supreme Court in the federal actiondescribed above. 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. 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. 267Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 2013, legislation intended toaccelerate gas infrastructure replacements in Maryland was signed into law. The law established a mechanism, separate from base rateproceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects incurred afterJune 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject to a cap and requirean annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in asubsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates.Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued adecision conditionally approving the first five years of BGE’s plan and surcharge. On November 16, 2015, BGE filed a surcharge update to beeffective January 1, 2016, including a true-up of cost estimates included in the 2015 surcharge, along with its 2016 project list and projectedcapital estimates of $113 million to be included in the 2016 surcharge calculation. The MDPSC subsequently approved BGE’s 2016 project list andthe proposed surcharge for 2016, which included the 2015 surcharge true-up. As of December 31, 2015, BGE recorded a regulatory asset of lessthan $1 million, representing the difference between the surcharge revenues and program costs. In 2014, the residential consumer advocate in Maryland appealed MDPSC’s decision on BGE’s infrastructure replacement plan andassociated surcharge with the Baltimore City Circuit Court, who affirmed the MDPSC’s decision. On October 10, 2014, the residential consumeradvocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court. During thethird quarter of 2015, the residential consumer advocate, MDPSC and BGE filed briefs. Oral argument in this matter was held before the Court ofSpecial Appeals on November 3, 2015. On January 28, 2016, the Maryland Court of Special Appeals issued a decision affirming the MDPSC’sdecision. New York Regulatory Matters Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). Ginna Nuclear Power Plant’s (Ginna)prior period fixed-price PPA contract with Rochester Gas & Electric Company (RG&E) expired in June 2014. In light of the expiration of the PPAand prevailing market conditions, in January 2014, Ginna advised the New York Public Service Commission (NYPSC) and the ISO-NY that, in theabsence of a reliability need, Ginna management 268Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) would make a recommendation, subject to approval by the CENG board, that the Ginna plant be retired as soon as practicable. A formal studyconducted by the ISO-NY and RG&E dated as of May 12, 2014 concluded that Ginna needs to remain in operation to maintain the reliability of thetransmission grid in the Rochester region through September 2018 when planned transmission system upgrades undertaken by RG&E areexpected to be completed. In November 2014, in response to a petition filed by Ginna, the NYPSC directed Ginna and RG&E to negotiate a Reliability Support ServicesAgreement (RSSA). In February 2015, regulatory filings, including RSSA terms negotiated between Ginna and RG&E, to support the continuedoperation of Ginna for reliability purposes were made with the NYPSC and with the FERC for their approval. Although the RSSA contract is stillsubject to such regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NYconsistent with the technical provisions of the proposed RSSA contract. In April 2015, the FERC issued an order which directed Ginna to make a compliance filing to ensure that the RSSA does not allow Ginna toreceive revenues above its full cost of service and which rejected any extension of the RSSA beyond its initial term; rather the order required thatany extension be subject to the rules currently being developed by the ISO-NY. The FERC order also set the RSSA for hearing and settlementprocedures. In response to the FERC’s April 2015 order, in May 2015, Ginna submitted a compliance filing to the FERC containing proposedrevisions to the RSSA addressing the FERC’s requirements and maintaining the April 1, 2015 proposed effective date. In July 2015, the FERCaccepted Ginna’s compliance filing effective April 1, 2015. The FERC accepted Ginna’s proposal for market revenue sharing subject to a capeffective April 1, 2015, and rejected requests for rehearing by intervenors on a number of matters related to jurisdiction, the reliability need, theRSSA term, and possible price suppression. In August 2015, Ginna reached a settlement in principle with intervenors modifying certain terms and conditions in the originally negotiatedagreement. The proposed RSSA under the settlement preserves the value of the contract originally negotiated with RG&E, but shortens the termfrom 3.5 to 2 years, expiring March 31, 2017 and required RG&E to complete a new transmission reliability study to determine whether an interimreliability solution is required beyond March 31, 2017. That reliability study was completed in October 2015, and it identified certain RG&E projectsthat are needed to solve reliability problems that would be caused by an early retirement of Ginna. Under the settlement agreement, Ginna wasrequired by December 29, 2015 to submit a bid to provide reliability services beginning April 1, 2017 until the necessary RG&E transmissionupgrades are in service, which RG&E expects will be no later than October 31, 2017. Ginna submitted such a bid in December 2015. RG&E hasthe right until June 30, 2016 to select Ginna as an ongoing reliability solution. If such a need exists, and if Ginna is selected, Ginna and RG&Ecould enter into an additional RSSA commencing April 1, 2017 on the rates, terms and conditions set forth in Ginna’s bid, or as might be otherwiseagreed by Ginna and RG&E. If RG&E seeks a reliability solution with Ginna, but RG&E and Ginna do not reach an agreement on rates, terms, and conditions of a newRSSA by March 31, 2016 (or by June 30, 2016 if RG&E elects to defer the decision date), the settlement agreement requires Ginna to file anunexecuted additional RSSA with the FERC for adjudication. If Ginna is not selected for continued reliability service and does not plan to retireshortly after the expiration of the RSSA, Ginna is required to file a notice to that effect with the NYPSC no later than September 30, 2016. Underthe terms of the proposed RSSA, if RG&E does not select Ginna to provide reliability service after March 31, 2017, and Ginna continues tooperate after June 14, 2017, Ginna would be required to make certain refund payments related to capital expenditures to RG&E. 269Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 August 2015 settlement was filed at the NYPSC and at the FERC in October 2015 and remains subject to review and approval by bothagencies; such reviews are not expected to be completed until the first quarter of 2016. Until final regulatory approvals are received, Generation is recognizing revenue based on market prices for energy and capacity delivered byGinna into the ISO-NY. Upon receiving regulatory approvals, under the RSSA contract terms, Generation would then recognize revenue based onthe final approved pricing contained in the contract retroactively from the April 1, 2015 effective date. While the RSSA is expected to receiveregulatory approvals and, therefore, permit Ginna to continue operating through the RSSA term, there is still a risk that, for economic reasons,including the possibility that the FERC or the NYPSC may condition the approval of the RSSA on a modification of the rates set forth in the RSSA,Ginna could be retired before 2029, which is the end of its operating license period. In the event the plant were to be retired before the currentlicense term ends in 2029, Exelon’s and Generation’s results of operations could be adversely affected by accelerated future decommissioningcosts, severance costs, increased depreciation rates, and impairment charges, among other items. However, it is not expected that such impactswould 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 filed with the FERC for that year’s reconciliation. As of December 31, 2015, and 2014, ComEd had a regulatory assetassociated with the transmission formula rate of $31 million and $21 million, respectively. As of December 31, 2015, and 2014, BGE had a netregulatory asset associated with the transmission formula rate of $12 million and $1 million, respectively. The regulatory asset associated withtransmission true-up is amortized to Operating revenues within their Consolidated Statements of Operations of Comprehensive Income as theassociated amounts are recovered through rates. 270Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 of the following years, the following total increases/(decreases) were included in ComEd’s and BGE’s electric transmission formularate filings: Annual Transmission Filings ComEd BGE 2015 2014 2013 2015 2014 2013 Initial revenue requirement increase $68 $36 $38 $— $9 $2 Annual reconciliation (decrease) increase 18 (14) 30 (3) 5 (3) Total revenue requirement increase $86 $22 $68 $(3) $14 $(1) Allowed return on rate base 8.61% 8.62% 8.7% 8.46% 8.53% 8.35% Allowed ROE 11.5% 11.5% 11.5% 11.3% 11.3% 11.3% Effective date of rates June 2015 June 2014 June 2013 June 2015 June 2014 June 2013 (a)For BGE, this excludes the increase in revenue requirement associated with dedicated facilities charges. The increases for dedicated facilities were $13 million and $3 million for2015 and 2014, respectively. There were no dedicated facilities charges in 2013 for BGE.(b)Refers to the weighted average debt and equity return on transmission rate bases for ComEd and BGE. As part of the FERC-approved settlement of ComEd’s 2007 transmissionrate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for thetransmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of BGE’s 2005 transmission rate case, the rate of return on common equity is11.30%, inclusive of a 50 basis point incentive for participating in PJM.(c)The time period for any challenges to the annual transmission formula rate update filings expired with no challenges submitted. 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 PHI 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 (and certain additional incentive basis points on certain projects). Theparties sought a reduction in the base return on equity to 8.7% and changes to the formula rate process. Under FERC rules, any revenues subjectto refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date ofthe 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. 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 created 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. On February 20, 2015, the Chief Judge issued an order consolidating the two complaint proceedings andestablished an Initial Decision issuance deadline of February 29, 2016. On November 6, 2015, BGE and the PHI companies and the complainants filed a settlement with FERC covering the issues raised in thecomplaints. The settlement provides for a 10% base ROE, effective March 8, 2016, which will be augmented by the PJM incentive adder of 50basis points, and refunds to BGE customers of $13.7 million. The settlement also provides a moratorium on any change in the ROE until June 1,2018. On December 16, 2015, the Presiding Administrative Law Judge submitted a Certification of the Uncontested Settlement to the FERCCommissioners. The settlement remains subject to FERC approval. 271(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)—(Continued) 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. A number of parties appealed to the U.S. Court of Appeals for the SeventhCircuit for review of the decision. In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC theissue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. Onremand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of theseorders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting anevidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. The hearing only concerns new facilities approved by the PJMBoard prior to February 1, 2013. As of December 31, 2015, settlement discussions are continuing. Because a new cost allocation had been adopted for projects approved by the PJM Board on or after February 1, 2013, this latest remandonly involves the cost allocation for facilities 500 kV and above approved prior to that date. ComEd anticipates that all impacts of any rate designchanges effective after December 31, 2006, should be recoverable through retail rates and, thus, the rate design changes are not expected to havea material impact on ComEd’s results of operations, cash flows or financial position. PECO anticipates that all impacts of any rate design changesshould be recoverable through the transmission service charge rider approved in PECO’s 2010 electric distribution rate case settlement and, thus,the rate design changes are not expected to have a material impact on PECO’s results of operations, cash flows or financial position. To theextent any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO’s results of operations. BGEanticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland shouldbe recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE’s results of operations,cash flows or financial position. ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to 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 2016 2017 2018 2019 2020 ComEd $297 $204 $61 $26 $6 $— PECO 67 31 24 8 4 — BGE 373 140 112 62 46 13 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 272Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)—(Continued) that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets were required topay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and was cost-effective. On January 25, 2016, the U.S. Supreme Court reversed the D.C. Circuit Court decision and remanded the matter to the D.C. CircuitCourt. While we cannot predict exactly how the D.C. Circuit Court will handle the matter on remand, we do not expect there will be any significantchange in how demand response resources have or will participate in and be paid by wholesale energy markets. Thus, we do not anticipate thatthere will be any impact to the Registrants’ results of operations or cash flows based on these proceedings. 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 27, 2015, ISO-NE filed the results of its ninth capacity auction (covering the June 1, 2018 through May 31, 2019 deliveryperiod). On June 18, 2015, the FERC accepted the results of the ninth capacity auction. On July 20, 2015, a union representing utility workerssought rehearing of that decision which the FERC denied on December 30, 2015. It is not clear whether the FERC’s order will be appealed. On February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 31, 2018 deliveryperiod). 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 mustfile additional information before the FERC can process the filing. ISO-NE filed the information on July 17, 2014, and the ISO-NE’s filings becameeffective by operation of law pursuant to a notice issued by the secretary of FERC on September 16, 2014. Several parties sought rehearing of thesecretary’s notice which was effectively denied in October 2014 and have since appealed the matter to the D.C. Circuit Court. On April 7, 2015 theD.C. Circuit Court issued an order referring the matter to a merits panel where issues raised by parties challenging the FERC decision will be heardas well as FERC’s Motion to Dismiss the challenges. It is not clear whether the court will decide ultimately on the merits of the case or whether itwill dismiss the case as FERC urges based on the fact that there is no action by the FERC to be considered. Nonetheless, while any change inthe auction results is thought to be unlikely, Exelon and Generation cannot predict with certainty what further action the court may take concerningthe results of that auction, but any court action could be material to Exelon’s and Generation’s expected revenues from the capacity auction. License Renewals (Exelon and Generation). Generation has 40-year operating licenses from the NRC for each of its nuclear units. Theoperating license renewal process takes approximately four to five years from the commencement of the renewal process until completion of theNRC’s review. On May 29, 2013, Generation submitted applications to the NRC to extend the current operating licenses of Byron Units 1 and 2 andBraidwood Units 1 and 2 by 20 years. On November 19, 2015, the NRC approved Generation’s request to extend the operating licenses of ByronUnit 1 and 2 by 20 years to 2044 and 2046, respectively. On January 27, 2016 the NRC approved Generation’s request to extend the operatinglicenses of Braidwood Unit 1 and 2 by 20 years to 2046 and 2047, respectively. On December 09, 2014, Generation submitted an application to the NRC to extend the current operating licenses of LaSalle Units 1 and 2,which were set to expire in 2022 and 2023, respectively. On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to FERC for 46-year licenses for theConowingo Hydroelectric Project (Conowingo) and the Muddy 273Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)—(Continued) Run Pumped Storage Project (Muddy Run), respectively. On December 22, 2015, FERC issued a new 40-year license for Muddy Run. The licenseterm expires on December 1, 2055. The financial impact associated with Muddy Run license commitments is estimated to be in the range of anincremental $25 million to $35 million, and includes both capital expenditures and operating expenses, primarily relating to fish passage and habitatimprovement projects. At December 31, 2015, $22 million of direct costs associated with the licensing effort have been capitalized. 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, Generation entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S.Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake BayProgram to design, conduct and fund an additional multi-year sediment study. Generation has agreed to contribute up to $3.5 million to fund theadditional study. Because states must act on applications under Section 401 of the CWA within one year and the sediment study would not becompleted prior to January 31, 2015, Exelon withdrew its application for a water quality certification on December 4, 2014. FERC policy requiresthat an applicant resubmit its request for a water quality certification within 90 days of the date of withdrawal. Accordingly, on March 3, 2015,Generation refiled its application for a water quality certification. Exelon has agreed with MDE to withdraw and refile its application for a waterquality certification as necessary pending completion of the sediment study. On August 7, 2015, US Fish and Wildlife Service (USFWS) submittedits modified fishway prescription to FERC in the Conowingo licensing proceedings. On September 11, 2015, Exelon filed a request for anadministrative hearing and proposed an alternative prescription to challenge USFWS’s preliminary prescription. Resolution of these issues relatingto Conowingo 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. The FERC license for Conowingo expired on September 1, 2014. Under the Federal Power Act, FERC is required to issue an annual licensefor a facility until the new license is issued. On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expirationof the previous license. If FERC does not issue a new license prior to the expiration of an annual license, the annual license will renewautomatically. On March 11, 2015, FERC issued the final Environmental Impact Statement for Conowingo. The stations are currently beingdepreciated over their estimated useful lives, which includes the license renewal period. As of December 31, 2015, $23 million of direct costsassociated 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. 274Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 31,2015 and 2014. December 31, 2015 Exelon ComEd PECO BGE Regulatory assets Pension and other postretirement benefits $3,156 $— $— $— Deferred income taxes 1,616 64 1,473 79 AMI programs 399 140 63 196 Under-recovered distribution service costs 189 189 — — Debt costs 47 46 1 8 Fair value of BGE long-term debt 162 — — — Severance 9 — — 9 Asset retirement obligations 108 67 22 19 MGP remediation costs 286 255 30 1 Under-recovered uncollectible accounts 52 52 — — Renewable energy 247 247 — — Energy and transmission programs 84 43 1 40 Deferred storm costs 2 — — 2 Electric generation-related regulatory asset 20 — — 20 Rate stabilization deferral 87 — — 87 Energy efficiency and demand response programs 279 — 1 278 Merger integration costs 6 — — 6 Conservation voltage reduction 3 — — 3 Under-recovered revenue decoupling 30 — — 30 CAP arrearage 7 — 7 — Other 35 10 19 3 Total regulatory assets 6,824 1,113 1,617 781 Less: current portion 759 218 34 267 Total noncurrent regulatory assets $6,065 $895 $1,583 $514 December 31, 2015 Exelon ComEd PECO BGE Regulatory liabilities Other postretirement benefits $94 $— $— $— Nuclear decommissioning 2,577 2,172 405 — Removal costs 1,527 1,332 — 195 Energy efficiency and demand response programs 92 52 40 — DLC program costs 9 — 9 — Electric distribution tax repairs 95 — 95 — Gas distribution tax repairs 28 — 28 — Energy and transmission programs 131 53 60 18 Over-recovered revenue decoupling 1 — — 1 Other 16 5 2 8 Total regulatory liabilities 4,570 3,614 639 222 Less: current portion 369 155 112 38 Total noncurrent regulatory liabilities $4,201 $3,459 $527 $184 275Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Exelon ComEd PECO BGE Regulatory assets Pension and other postretirement benefits $3,256 $— $— $— Deferred income taxes 1,542 64 1,400 78 AMI programs 296 91 77 128 Under-recovered distribution service costs 371 371 — — Debt costs 57 53 4 9 Fair value of BGE long-term debt 190 — — — Severance 12 — — 12 Asset retirement obligations 116 74 26 16 MGP remediation costs 257 219 37 1 Under-recovered uncollectible accounts 67 67 — — Renewable energy 207 207 — — Energy and transmission programs 48 33 — 15 Deferred storm costs 3 — — 3 Electric generation-related regulatory asset 30 — — 30 Rate stabilization deferral 160 — — 160 Energy efficiency and demand response programs 248 — — 248 Merger integration costs 8 — — 8 Conservation voltage reduction 2 — — 2 Under-recovered revenue decoupling 7 — — 7 Other 46 22 14 7 Total regulatory assets 6,923 1,201 1,558 724 Less: current portion 847 349 29 214 Total noncurrent regulatory assets $6,076 $852 $1,529 $510 December 31, 2014 Exelon ComEd PECO BGE Regulatory liabilities Other postretirement benefits $88 $— $— $— Nuclear decommissioning 2,879 2,389 490 — Removal costs 1,566 1,343 — 223 Energy efficiency and demand response programs 59 25 34 — DLC program costs 10 — 10 — Electric distribution tax repairs 102 — 102 — Gas distribution tax repairs 49 — 49 — Energy and transmission programs 84 19 58 7 Revenue subject to refund 3 3 — — Over-recovered revenue decoupling 12 — — 12 Other 8 1 4 2 Total regulatory liabilities 4,860 3,780 747 244 Less: current portion 310 125 90 44 Total noncurrent regulatory liabilities $4,550 $3,655 $657 $200 Pension and other postretirement benefits. As of December 31, 2015, Exelon had regulatory assets of $3,156 million and regulatoryliabilities of $94 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 276Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 costs associated with Exelon’s other postretirement benefit plans. PECO’s pension regulatory recovery is based on cash contributionsand is not included in the regulatory asset (liability) balances. The regulatory asset (liability) is amortized in proportion to the recognition of priorservice costs (gains), transition obligations and actuarial losses (gains) attributable to Exelon’s pension and other postretirement benefit plansdetermined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. ComEd, PECO and BGE willrecover these costs through base rates as allowed in their most recently approved regulated rate orders. The pension and other postretirementbenefit regulatory asset balance includes a regulatory asset established at the date of the Constellation merger related to BGE’s portion of thedeferred costs associated with legacy Constellation’s pension and other postretirement benefit plans. The BGE-related regulatory asset is beingamortized over a period of approximately 12 years, which generally represents the expected average remaining service period of plan participantsat the date of the Constellation merger. See Note 17—Retirement Benefits for additional detail. No return is earned on Exelon’s regulatory asset. Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of 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 BGE, thisamount includes the impacts of a reduction in the deductibility, for Federal income tax purposes, of certain retiree health care costs pursuant tothe March 2010 Health Care Reform Acts. For BGE, these additional income taxes are being amortized over a 5-year period that began in March2011 in accordance with the MDPSC’s March 2011 rate order. For PECO, this amount includes the impacts of electric and gas distribution repairsin the deductibility pursuant to PUC’s 2010 and 2015 rate case settlement agreements. See Note 15—Income Taxes and Note 17—RetirementBenefits for additional information. ComEd, PECO and BGE are not earning a return on the regulatory asset in base rates. AMI programs. For ComEd, this amount represents meter costs associated with ComEd’s AMI pilot program approved in ComEd’s 2010rate case. The recovery periods for the meter costs are through January 1, 2020. As of December 31, 2015 and December 31, 2014, ComEd hadregulatory assets of $137 million and $88 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 over recovery. The approved plan also provides forrecovery of accelerated depreciation on PECO’s non-AMI meter assets over a 10-year period ending December 31, 2020. Recovery of smart metercosts will be reflected in base rates effective January 1, 2016. For BGE, this amount represents smart grid pilot program costs as well as theincremental costs associated with implementing full deployment of a smart grid program. Pursuant to a MDPSC order, pilot program costs of $11million were deferred in a regulatory asset, and, beginning with the MDPSC’s March 2011 rate order, is earning BGE’s most current authorized rateof return. In August 277Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2010, the MDPSC approved a comprehensive smart grid initiative for BGE, authorizing BGE to establish a separate regulatory asset forincremental costs incurred to implement the initiative, including the net depreciation and amortization costs associated with the meters, and anappropriate rate of return on these costs, a portion of which is not recognized under GAAP until cost recovery begins. Additionally, the MDPSCrequires that BGE prove the cost-effectiveness of the entire smart grid initiative prior to seeking recovery of the costs deferred in these regulatoryassets. As part of the 2015 electric and gas distribution rate case filed on November 6, 2015 and amended on January 5, 2016, BGE is seekingrecovery of its smart grid initiative costs. Of BGE’s requested $200 million, $140 million relates to the smart grid initiative. In support of itsrecovery of smart grid initiative costs, BGE provided evidence demonstrating that the benefits exceed the costs by a ratio of 2.3 to 1.0, on anominal basis. If approved by the MDPSC, the amortization of these deferred costs would begin in June 2016. BGE’s AMI regulatory assetexcludes costs for non-AMI meters being replaced by AMI meters, as recovery of those costs commenced with the new rates approved andimplemented with the MDPSC order in BGE’s 2014 electric and gas distribution case. Under-recovered distribution services costs. These amounts represent under (over) recoveries related to electric distribution servicescosts recoverable (refundable) through EIMA’s performance based formula rate tariff. Under (over) recoveries for the annual reconciliations arerecoverable (refundable) over a one-year period and costs for certain one-time events, such as large storms, are recoverable over a five-yearperiod. ComEd earns and pays a return on under and over recovered costs, respectively. As of December 31, 2015, the regulatory asset wascomprised of $142 million for the 2014 and 2015 annual reconciliations and $47 million related to significant one-time events, including $36 millionin deferred storm costs and $11 million of Constellation merger and integration related costs. As of December 31, 2014, the regulatory asset wascomprised of $286 million for the 2013 and 2014 annual reconciliations and $85 million related to significant one-time events, including $66 millionin deferred storm costs and $19 million of Constellation merger and integration related costs. See Energy Infrastructure Modernization Act abovefor further details. 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. Severance. For BGE, these costs represent deferred severance costs associated with a 2010 workforce reduction that were deferred as aregulatory asset and are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order.Additionally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance with theMDPSC’s orders in prior rate cases and are being amortized over a 5-year period that began in July 2012. BGE is earning a regulated return on theregulatory asset included in base rates. 278Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 16—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 recovery of actual clean-up costs on a site-specific basis in distribution rates.For BGE, $5 million of clean-up costs incurred during the period from July 2000 through November 2005 and an additional $1 million fromDecember 2005 through November 2010 are recoverable through rates in accordance with MDPSC orders. BGE is earning a return on thisregulatory asset and these costs are being amortized over 10-year periods that began in January 2006 and December 2010, respectively. Therecovery period for the 10-year period that began January 2006 was extended for an additional 24 months, in accordance with the MDPSCapproved 2014 electric and natural gas distribution rate case order. See Note 23—Commitments and Contingencies for additional information. Under recovered uncollectible accounts. These amounts represent the difference between ComEd’s annual uncollectible accountsexpense and revenues collected in rates through an ICC-approved rider. The difference between net uncollectible account charge-offs andrevenues collected through the rider each calendar year is recovered or refunded over a twelve-month period beginning in June of the followingcalendar year. ComEd does not earn a return on these under recoveries. Renewable energy. In December 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 at the market priceand the contracted price. Energy and transmission programs. These amounts represent under (over) recoveries related to energy and transmission costsrecoverable (refundable) under ComEd’s ICC and/or FERC-approved rates. Under (over) recoveries are recoverable (refundable) over a one-yearperiod or less. ComEd earns a return or interest on under-recovered costs and pays interest on over-recovered costs to customers. As ofDecember 31, 2015, ComEd’s regulatory asset of $43 million included $5 million related to under-recovered energy costs, $31 million associatedwith transmission costs recoverable through its FERC-approved formula rate tariff, and $7 million of Constellation merger and integration costs tobe recovered upon FERC approval. As of December 31, 2015, ComEd’s regulatory liability of $53 million included $29 million related to over-recovered energy costs and $24 million associated with revenues received for renewable energy requirements. As of December 31, 2014,ComEd’s regulatory asset of $33 million included $4 million related to under-recovered energy costs, $22 million associated with transmissioncosts recoverable through its FERC-approved formula rate tariff, and $7 million of 279Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 merger and integration costs to be recovered upon FERC approval. As of December 31, 2014, ComEd’s regulatory liability of $19million included $3 million related to over-recovered energy costs and $16 million associated with revenues received for renewable energyrequirements. See Transmission Formula Rate above for further details. 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, the DSP Program costs are presented on a net basis with PECO’s GSA under (over)-recovered energy costs.See additional discussion below. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSCunder which PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2015,PECO had a regulatory liability that included $35 million related to the DSP program, $22 million related to over-recovered natural gas supply costsunder the PGC and $3 million related to over-recovered electric transmission costs. As of December 31, 2014, PECO had a regulatory liability thatincluded $39 million related to the DSP program, $3 million related the over-recovered electric transmission costs and $16 million related to over-recovered natural gas supply costs under the PGC. DSP Program Costs. These amounts represent recoverable administrative costs incurred relating to the filing and procurement associatedwith PECO’s PAPUC-approved DSP programs for the procurement of electric supply. The filings and procurements of these DSP Programs arerecoverable through the GSA over each respective term. The original DSP Program had a 29-month term that began January 1, 2011. DSP II andDSP III each have a 24-month term that began June 1, 2013 and June 1, 2015, respectively. The independent evaluator costs associated withconducting procurements are recoverable over a 12-month period after the PAPUC approves the results of the procurements. PECO is not earninga return on these costs. Certain costs included in PECO’s original DSP program related to information technology improvements were recoveredover a 5-year period that began January 1, 2011. PECO earns a return on the recovery of information technology costs. These costs are includedwithin the energy and transmission programs line item. The BGE energy costs represent the electric supply, gas supply, and transmission related costs recoverable (refundable) from (to)customers under BGE’s market-based SOS program, MBR program, and FERC approved transmission rates, respectively. BGE does not earn orpay interest on under- or over-recovered costs to customers. As of December 31, 2015, BGE’s regulatory asset of $40 million included $12 millionassociated with transmission costs recoverable through its FERC approved formula rate and $28 million related to under-recovered electric energycosts. As of December 31, 2015, BGE’s regulatory liability of $18 million related to $5 million of over-recovered natural gas costs $14 million ofover-recovered transmission costs, offset by $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014,BGE’s regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger andintegration costs and $1 million of transmission costs recoverable through its FERC approved formula rate. As of December 31, 2014, BGE’sregulatory liability of $7 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. BGE earns a return on this regulatory asset and the recovery period was extended for an additional 25 months, in accordance with theMDPSC approved 2014 electric and natural gas distribution rate case order. 280Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 $19 million as of December 31, 2015, and $28 million as of December 31,2014. 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 2015 and 2014, BGE recovered $73 million and $65 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. For ComEd, these amounts represent over recoveries related to ComEd’s ICC-approved Energy Efficiency and Demand Response Plan. ComEd refunds these over recoveries through a rider over a twelve-month period.ComEd earns a return on the capital investment incurred under the program, but does not earn or pay interest on under or over recoveries,respectively. For PECO, these amounts represent over recoveries of program costs related to both Phase I and Phase II of its PAPUC-approvedEE&C Plan. PECO began recovering the costs of its Phase I and Phase II EE&C Plans through a surcharge in January 2010 and June 2013,respectively, based on projected spending under the programs. Phase I recovery continued over the life of the program, which expired on May 31,2013 and excess funds collected began being refunded in June 2013. Phase II of the program began on June 1, 2013, and will continue over thelife of the program, which will expire on May 31, 2016. Excess funds collected are required to be refunded beginning in June 2016. PECO earned areturn on the capital investment incurred under Phase I of the program. PECO does not earn (pay) interest on under (over) collections. For BGE,these amounts represent under (over) recoveries related to BGE’s Smart Energy Savers Program, which includes both MDPSC-approved demandresponse and energy efficiency programs. For the BGE Peak Rewards demand response program which began in January 2008, actualmarketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from thedate incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of theequipment. Also included in the demand response program are customer bill credits related to BGE’s Smart Energy Rewards program which beganin July 2013 and are being recovered through the surcharge. Actual costs incurred in the energy efficiency program are being amortized over a 5-year period with recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a rate of return on the capital investments anddeferred costs incurred under the program and earns (pays) interest on under (over) collections. 281®SMSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 31,2015, BGE had a regulatory asset of $30 million related to under-recovered electric revenue decoupling and a regulatory liability of $1 millionrelated to over-recovered natural gas revenue decoupling. As of December 31, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12 million related to over-recovered natural gas revenue decoupling. CAP arrearage. These amounts represent the guaranteed recovery of previously incurred bad debt expense associated with the estimatedeligible CAP accounts receivable balances under the IPAF Program as provided by the 2015 electric distribution rate case settlement. Thesecosts are amortized as recovery is received through a combination of customer payments and rate recovery, including through future rate cases ifnecessary. PECO is not earning a return on this regulatory asset. 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. Exelon is not accruing interest on these costs. See Note 16—Asset RetirementObligations 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. PECO’s 2015 electric distribution rate case settlement requires PECOto pay interest on the unamortized balance of the tax-effected catch-up deduction beginning January 1, 2016. 282Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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. 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, 2015, and December 31, 2014, ComEdowed $0 million and $3 million, respectively. 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 and BGE purchase receivables at a discount to primarilyrecover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recoveruncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO, and BGE do not record unbilled commodityreceivables under their POR programs. Purchased billed receivables are classified in other accounts receivable, net on Exelon’s, ComEd’s,PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants asof December 31, 2015 and 2014. As of December 31, 2015 Exelon ComEd PECO BGE Purchased receivables $229 $103 $67 $59 Allowance for uncollectible accounts (31) (16) (7) (8) Purchased receivables, net $198 $87 $60 $51 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 (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. The implementation costs were fully recovered and the 1% discount was reset to 0%, effective July 2015.(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. 4. Mergers, Acquisitions, and Dispositions (Exelon and Generation) 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 283 (a) (b) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) combine the two companies in an all cash transaction. The resulting company will retain the Exelon name. Under the Merger Agreement, PHI’sshareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Based on the outstanding shares of PHI’s commonstock as of December 31, 2015, PHI shareholders would receive $6.9 billion in total cash. In addition, in connection with the Merger Agreement,Exelon entered into a subscription agreement under which it has purchased $180 million of a class of nonvoting, nonconvertible andnontransferable preferred securities of PHI. The preferred securities are included in Other non-current assets on Exelon’s Consolidated BalanceSheet. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any. On November 2, 2015, Exelon and PHI each filed a new Notification and Report Form with the DOJ under the Hart-Scott-Rodino AntitrustImprovements Act of 1976 (HSR Act) due to the expiration of the original filing. The HSR Act waiting period expired on December 2, 2015, and theHSR Act no longer precludes completion of the merger. To date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU), the DelawarePublic Service Commission (DPSC), the Maryland Public Service Commission (MDPSC) and the FERC have approved the merger of PHI andExelon. The Federal Communications Commission has also approved the transfer of certain PHI communications licenses. On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI,Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits to ACEcustomers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregatevalue of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million. The March 6,2015, order by the NJBPU approving the merger required that the consummation of the merger must take place no later than November 1, 2015unless otherwise extended by the Board. On October 15, 2015, the NJBPU extended the November 1, 2015 date to June 30, 2016. On February 13, 2015, Exelon and PHI announced that they had reached a settlement agreement in the proceeding before the DPSC toreview the proposed merger. The settlement, which was amended on April 7, 2015, was signed and filed by Exelon, PHI, Delmarva Power & LightCompany (DPL), the DPSC Staff, the Delaware Public Advocate, the Delaware Department of Natural Resources and Environmental Control, theDelaware Sustainable Energy Utility, the Mid-Atlantic Renewable Energy Coalition and the Clean Air Council. As part of this settlement, Exelonand PHI proposed a package of benefits to DPL customers and the state of Delaware including the establishment of customer rate credits of $40million for DPL customers in Delaware, $2 million of funding for energy efficiency programs for DPL low income customers, and $2 million offunding for workforce development. On June 2, 2015, the DPSC issued an order accepting the settlement and approving the merger betweenExelon and PHI. On March 17, 2015, Exelon and PHI announced that they had reached settlements with multiple parties in the Maryland proceeding to reviewthe proposed merger after filing a Request for Adoption of Settlements with the MDPSC. The settlements were signed and filed by Exelon, PHI,Montgomery County, Prince George’s County, the National Consumer Law Center, National Housing Trust, the Maryland Affordable HousingCoalition, the Housing Association of Nonprofit Developers, and a consortium of recreational trail advocacy organizations led by the Mid-AtlanticOff-Road Enthusiasts. 284Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 and PHI also announced a settlement with The Alliance for Solar Choice. On May 15, 2015, the MDPSC approved the merger aftermodifying a number of the conditions in the settlements, resulting in total rate credits of $66 million, funding for energy efficiency programs of$43.2 million, a Green Sustainability Fund of $14.4 million, 20 MWs of renewable generation development and increased penalties related toreliability commitments. On May 18, 2015, Exelon and PHI accepted and committed to fulfill the conditions. On June 11, 2015, the Maryland Office of People’s Counsel (OPC), the Sierra Club, and the Chesapeake Climate Action Network filedPetitions for Judicial Review of the MDPSC’s approval of the merger with the Circuit Court for Queen Anne’s County. On June 23, 2015, PublicCitizen, Inc. filed its Petition for Judicial Review with the Circuit Court for Queen Anne’s County. On July 10, 2015, Exelon and PHI filed aresponse in opposition to the Petitions for Review. On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery andpresentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 theSierra Club and the Chesapeake Climate Action Network filed a joint motion to stay. In July and August, Exelon, PHI, the MDPSC, PrinceGeorge’s County and Montgomery County filed responses opposing the motions to stay. The judge issued an order denying the motions for stayon August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions forjudicial review filed by the OPC, the Sierra Club, the Chesapeake Climate Action Network (CCAN) and Public Citizen, Inc. On January 19, 2016,the OPC filed a notice of appeal to the Maryland Court of Special appeals, and on January 21, Sierra Club and CCAN filed a notice of appeal. Inthe ordinary course this appeal would be resolved no earlier than third quarter 2016. On August 27, 2015, the District of Columbia Public Service Commission (DCPSC) issued an Opinion and Order denying approval of themerger, concluding that the merger as presented was not in the public interest. Exelon and PHI filed an Application for Reconsideration with theDCPSC on September 28, 2015. On October 6, 2015, Exelon, PHI, the District of Columbia Government, the Office of Peoples Counsel, theDistrict of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust—Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties)entered into a Nonunanimous Full Settlement Agreement and Stipulation (Settlement Agreement) with respect to the merger. Exelon and PHIsubsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of theSettlement Agreement and granting additional requested relief. The new package of benefits totals $78 million and includes commitments toprovide relief of residential customer base rate increases of $26 million, one-time direct bill credits of $14 million, low-income energy assistance of$16 million, improved reliability, a cleaner and greener D.C. through funding energy efficiency programs and development of renewable energy, andinvestment in local jobs and the local economy through workforce development of $5 million. It also guarantees charitable contributions totaling$19 million over 10 years. On October 28, 2015, the DCPSC agreed to reopen the approval application to allow for consideration of the Settlement Agreement. Sincethen, parties supporting and opposing the Settlement filed testimony, participated in formal hearings and, on December 23, 2015, submitted finalbriefs to the DCPSC. The parties now await a formal decision from the DCPSC. The Merger Agreement provides that either Exelon or PHI mayterminate the Merger Agreement if the merger is not completed by October 28, 2015. Pursuant to a Letter Agreement related to the SettlementAgreement, Exelon and PHI have agreed, among other things, that they will not exercise their rights to terminate 285Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Merger Agreement before March 4, 2016, except under limited circumstances. If the DCPSC does not approve the Settlement Agreement byMarch 4, 2016, either Exelon or PHI may terminate the Settlement Agreement. The settlements reached and commission orders received to date in Delaware, Maryland and New Jersey include a “most favored nation”provision which, generally speaking, requires allocation of merger benefits proportionately across all the jurisdictions. When applying the mostfavored nation provision to the settlement terms and other conditions established in the merger approvals received to date, and as proposed in theSettlement Agreement filed with the DCPSC, Exelon and PHI currently estimate direct benefits of $430 million or more on a net present valuebasis (excluding charitable contributions and renewable generation commitments) will be provided, including rate credits, funding for energyefficiency programs and other required commitments. Exelon and PHI anticipate substantially all of such amounts will be charged to earnings atthe time of merger close and will be paid by the end of 2017. An additional $53 million will be charged to earnings at the time of the merger closefor charitable contributions, which are then required to be paid over a period of 10 years. Commitments to develop renewable generation, which areexpected to be primarily capital in nature, will be recognized as incurred. Upon completion of the merger, the actual nature, amount, timing andfinancial reporting treatment for these commitments may be materially different from the current projection. 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. Exelon wasalso named in a federal court suit making similar claims. In September 2014, the parties reached a proposed settlement that would resolve allclaims, which is subject to court approval. Final court approval of the proposed settlement is not anticipated until approximately 90 days aftermerger close. Exelon does not believe these suits will impact the completion of the transaction, and they are not expected to have a materialimpact on Exelon’s results of operations. Including 2014 and through December 31, 2015, Exelon has incurred approximately $259 million of expense associated with the proposedmerger. Of the total costs incurred, $121 million is primarily related to acquisition and integration costs and $138 million are for costs incurred tofinance the transaction. The financing costs include $22 million of costs associated with the private exchange offer and redemption of certainSenior Unsecured Notes (see Note 14—Debt and Credit Agreements for further information on the exchange), as well as, a net loss of $64 millionrelated to the settlement of forward-starting interest-rate swaps. These swaps were terminated in connection with the $4.2 billion issuance of debt;refer to Note 13—Derivative Financial Instruments for more information. The financing costs exclude costs to issue equity and the initial debtoffering which we recorded to Exelon’s Consolidated Balance Sheets. For the year ended, Acquisition, Integration and Financing Costs 2015 2014 Exelon $80 $179 Generation 25 11 ComEd 10 4 PECO 5 2 BGE 5 2 286(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statement of Operations and ComprehensiveIncome, with the exception of the financing costs, which are included within Interest expense. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259million to $293 million plus certain expenses. If the Merger Agreement is terminated due to a failure to obtain a required regulatory approval,Exelon may be required to pay PHI a termination fee equal to $180 million through the redemption by PHI of the outstanding nonvoting preferredsecurities described above for no consideration other than the nominal par value of the stock, plus reimbursement of PHI’s documented out-of-pocket expenses up to a maximum of $40 million. Merger Financing Exelon has raised cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments, through theissuance of $4.2 billion of debt (of which $3.3 billion remains after execution of the exchange offer, see Note 14—Debt and Credit Agreements forfurther information on the exchange), $1.15 billion of junior subordinated notes in the form of 23 million equity units, the issuance of $1.9 billion ofcommon stock, cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion) and theremaining balance from cash on hand and/or short-term borrowings available to Exelon. Exelon will have sufficient cash to fund the all-cashpurchase price, acquisition and integration related costs, and merger commitments. See Note 14—Debt and Credit Agreements and Note 19—Shareholder’s Equity for further information on the debt and equity issuances. 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. (IES) for a purchase price of $332 million,including net working capital. Generation has elected to account for the transaction as an asset acquisition for federal income tax purposes. Thegeneration and solar asset businesses of Integrys are excluded from the transaction. The Purchase Agreement also includes variousrepresentations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature. 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. 287Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 $390 Mark-to-market derivative assets 184 Unamortized energy contract assets 115 Customer relationships 50 Working capital liabilities (196) Mark-to-market derivative liabilities (57) Unamortized energy contract liabilities (110) Deferred tax liability (16) Total net identifiable assets, at fair value $360 Bargain purchase gain (after-tax) $28 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 revenues 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 $386 million and $(42) million, respectively. The net loss for the periodfrom November 1, 2014 to December 31, 2014 includes pre-tax unrealized losses on derivative contracts of $108 million and the bargain purchasegain of $28 million. It is impracticable to determine the overall financial statement impact of IES for 2015 due to the integration of the business intoongoing operations. For the years ended December 31, 2015 and 2014, Exelon and Generation incurred $5 million and $7 million, respectively, ofmerger and integration related costs which are included within Operating and maintenance expense in Exelon’s and Generation’s ConsolidatedStatements of Operations and Comprehensive Income. 288Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 for the year ended December 31, 2014. The proceeds are expected to be usedprimarily to finance a portion of the merger with PHI. Station NetGenerationCapacity Location Operating Segment PercentOwnedFore 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% 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. Assets held for sale at December 31, 2015 are not material. 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 for the year ended December 31, 2014. See Note 8—Impairment of Long-Lived Assets for furtherinformation.(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) Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation has historically had various agreements with CENGto purchase power and to provide certain services. For further information regarding these agreements, see Note 26—Related Party Transactions. On April 1, 2014, Generation and subsidiaries of Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA)pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate andadministrative services for 289(a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDF’s rights as a member of CENG(the Integration Transaction). CENG will reimburse Generation for its direct and allocated costs for such services. As part of the arrangement, NineMile Point Nuclear Station, LLC, a subsidiary of CENG, also assigned to Generation its obligations as Operator of Nine Mile Point Unit 2 under anoperating agreement with Long Island Power Authority, the Unit 2 co-owner. In addition, on April 1, 2014, the Power Services Agency Agreement(PSAA) was amended and extended until the permanent cessation of power generation by the CENG generation plants. In addition, on April 1, 2014, Generation made a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out ofspecified available cash flows of CENG or payable upon the maturity date of April 1, 2034. Immediately following receipt of the proceeds of suchloan, CENG made a $400 million special distribution to EDF. Unpaid principal and accrued interest on the loan was $300 million as ofDecember 31, 2015. Exelon, Generation, and subsidiaries of Generation, EDF and CENG also executed a Fourth Amended and Restated Operating Agreementfor CENG on April 1, 2014, pursuant to which, among other things, CENG committed to make preferred distributions to Generation (afterrepayment of the $400 million loan and associated interest) quarterly out of specified available cash flows until Generation has received aggregatedistributions of $400 million plus a return of 8.5% per annum from April 1, 2014 (Preferred Distribution Rights). Generation and EDF also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has the option, exercisable beginningon January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determinedby agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF’s 49.99%interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG OperatingAgreement, including Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return, and the value ofGeneration’s rights to other distributions. Under limited circumstances, the period for exercise of the put option may be extended for 18 months. Inorder to exercise its option, EDF must give 60 days advance written notice to Generation stating that it is exercising its option. As of the datethese financial statements were issued, EDF has not given notice to Generation that it is exercising its option. On April 1, 2014, Generation also executed an Indemnity Agreement pursuant to which Generation indemnified EDF against third-partyclaims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or theiroperations. Exelon guarantees Generation’s obligations under this indemnity. In addition, on April 1, 2014, Generation, EDF, 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 290Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) payment schedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG. However, inthe event that EDF exercises its rights under the Put Option, all payments not made as of the put closing date shall accelerate to be paidimmediately prior to such closing date. 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 in CENG and $56 million of revenues from CENG. The book value ofGeneration’s investment in CENG prior to the consolidation was $1.9 billion, and the book value of the AOCI related to CENG prior to consolidationwas $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 Exelon’s affiliates that are considered related party transactions to Generation. As furtherdescribed in Note 26—Related Party Transactions, EDF and Generation had a PPA with CENG under which they purchased 15% and 85%,respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs through December 31, 2014.Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation purchase 49.99% and 50.01%,respectively, of the nuclear output owned by CENG not subject to other contractual agreements. Beginning April 1, 2014, CENG’s sales toGeneration have been eliminated in consolidation. For the years ended December 31, 2015 and 2014, Generation had sales to EDF of $488 millionand $137 million, respectively. See discussion above and Note 2—Variable Interest Entities for additional information regarding other transactionsbetween CENG and EDF included within Exelon and Generation’s consolidated financial statements and for additional information about theRegistrants VIE’s. 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 291Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing transactions between CENG andGeneration. 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 were 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 couldbe modified for up to one year from April 1, 2014, as more information was obtained about the fair value of assets and liabilities. The principalitems that have been revised include the asset retirement obligation liabilities and related asset retirement costs. These items have been updatedwith inputs from a third party engineering firm with corresponding adjustments recorded in 2014 and the first quarter of 2015. See Note 16—AssetRetirement Obligations for discussion of the impacts of adjustments recorded during 2014 and 2015 related to updated estimates of the CENGasset retirement obligation liabilities. In the period of such revisions, these and any other material changes to the fair value assessments haveresulted in adjustments to the amounts recorded upon consolidation. In addition, the asset or liability adjustments impacting depreciation and/oraccretion expense recorded after the consolidation date have impacted Generation’s post-consolidation results of operations. 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 3,073 Nuclear fuel 482 Other assets 10 Total assets 6,019 Current liabilities 237 Asset retirement obligation 1,816 Pension and other employee benefit obligations 281 Unamortized energy contract liabilities 171 Other liabilities 114 Total liabilities 2,619 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. 292Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 years endedDecember 31, 2015 and 2014, Generation reduced by $18 million and $13 million, respectively, the amount of Net income attributable tononcontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of theconsolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incrementaloperating revenues of $509 million and $218 million and CENG’s net income (loss), prior to any intercompany eliminations and any adjustments fornoncontrolling interest, of $(11) million and $407 million during the years ended December 31, 2015 and 2014, respectively. Exelon and Generation incurred integration-related costs of $2 million and $26 million for the year ended December 31, 2015 and 2014,respectively. The costs incurred are classified primarily within Operating and maintenance expense in Exelon’s and Generation’s respectiveConsolidated Statements of Operations and Comprehensive Income. 6. Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE) Accounts receivable at December 31, 2015 and 2014 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: 2015 Exelon Generation ComEd PECO BGE Unbilled customer revenues $1,203 $732 $218 $105 $148 Allowance for uncollectible accounts (284) (77) (75) (83) (49) 2014 Exelon Generation ComEd PECO BGE Unbilled customer revenues $1,381 $823 $204 $140 $214 Allowance for uncollectible accounts (311) (60) (84) (100) (67) (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)Excludes the non-current allowance for uncollectible accounts of $8 million at both December 31, 2015 and 2014, related to PECO’s current installment plan receivables describedbelow.(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 at both 293(a) (b)(c)(a) (b)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of theinstallment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1—Significant AccountingPolicies. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2015 and December 31, 2014 of$15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The 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, 2015 and 2014 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. 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, 2015 and 2014: AverageService Life(years) 2015 2014 Asset Category Electric—transmission and distribution 5-90 $32,546 $30,157 Electric—generation 1-56 25,615 22,911 Gas—transportation and distribution 5-90 3,864 3,505 Common—electric and gas 5-50 1,149 1,169 Nuclear fuel 1-8 6,384 5,947 Construction work in progress N/A 3,075 2,167 Other property, plant and equipment 5-50 1,181 1,056 Total property, plant and equipment 73,814 66,912 Less: accumulated depreciation 16,375 14,742 Property, plant and equipment, net $57,439 $52,170 (a)Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively.(b)Includes Generation’s buildings under capital lease with a net carrying value of $13 million and $15 million at December 31, 2015 and 2014, respectively. The original cost basis ofthe buildings was $52 million, and total accumulated amortization was $39 million and $37 million, as of December 31, 2015 and 2014, respectively. Also includes ComEd’sbuildings under capital lease with a net carrying value at December 31, 2015 and 2014, of $7 million and $8 million, respectively. The original cost basis of the buildings was $8million and total accumulated amortization was $1 million and $0.3 million as of December 31, 2015 and 2014, respectively. Includes land held for future use and non utilityproperty at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and explorationcosts of $266 million and $242 million related to oil and gas production activities at Generation at December 31, 2015 and 2014, respectively. Includes the original cost andprogress payments associated with Generation’s turbine equipment held for future use with a carrying value of $146 million and $83 million at December 31, 2015 and 2014,respectively.(c)Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively. 294 (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 annual depreciation provisions as a percentage of average service life for each asset category. Average Service Life Percentage by Asset Category 2015 2014 2013 Electric—transmission and distribution 2.83% 2.93% 2.91% Electric—generation 3.47% 3.50% 3.35% Gas 2.17% 2.13% 2.06% Common—electric and gas 7.79% 7.32% 7.53% Generation The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014: Average Service Life(years) 2015 2014 Asset Category Electric—generation 1-56 $25,615 $22,911 Nuclear fuel 1-8 6,384 5,947 Construction work in progress N/A 2,017 1,404 Other property, plant and equipment 5-31 466 378 Total property, plant and equipment 34,482 30,640 Less: accumulated depreciation 8,639 7,612 Property, plant and equipment, net $25,843 $23,028 (a)Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively.(b)Includes buildings under capital lease with a net carrying value of $13 million and $15 million at December 31, 2015 and 2014, respectively. The original cost basis of the buildingswas $52 million, and total accumulated amortization was $39 million and $37 million, as of December 31, 2015 and 2014, respectively. These balances also include capitalizedacquisition, development and exploration costs of $266 million and $242 million related to oil and gas production activities at Generation at December 31, 2015 and 2014,respectively. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $146 million and $83million at December 31, 2015 and 2014, respectively.(c)Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively. The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.47%, 3.50% and 3.35% forthe years ended December 31, 2015, 2014 and 2013, 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 material impact on the Consolidated Statements of Operations and Comprehensive Income. See Note 3—Regulatory Matters for additional information regarding license renewals. 295(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014: Average Service Life(years) 2015 2014 Asset Category Electric—transmission and distribution 5-80 $20,576 $18,884 Construction work in progress N/A 572 276 Other property, plant and equipment 38-50 64 65 Total property, plant and equipment 21,212 19,225 Less: accumulated depreciation 3,710 3,432 Property, plant and equipment, net $17,502 $15,793 (a)Includes buildings under capital lease with a net carrying value at December 31, 2015 and 2014 of $7 million and $8 million, respectively. The original cost basis of the buildingswas $8 million and total accumulated amortization was $1 million and $0.3 million as of December 31, 2015 and 2014, respectively.(b)Includes land held for future use and non-utility property. The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 3.03%,3.05% and 2.97% for the years ended December 31, 2015, 2014 and 2013, respectively. PECO The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014: Average Service Life(years) 2015 2014 Asset Category Electric—transmission and distribution 5-65 $7,230 $6,886 Gas—transportation and distribution 5-70 2,206 2,039 Common—electric and gas 5-50 631 618 Construction work in progress N/A 154 154 Other property, plant and equipment 50 21 21 Total property, plant and equipment 10,242 9,718 Less: accumulated depreciation 3,101 2,917 Property, plant and equipment, net $7,141 $6,801 (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 2015 2014 2013 Electric—transmission and distribution 2.39% 2.55% 2.73% Gas 1.87% 1.84% 1.79% Common—electric and gas 5.16% 5.16% 6.65% 296 (a), (b) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014: Average Service Life(years) 2015 2014 Asset Category Electric—transmission and distribution 5-90 $6,663 $6,339 Gas—distribution 5-90 1,951 1,761 Common—electric and gas 5-40 655 623 Construction work in progress N/A 312 317 Other property, plant and equipment 20 32 32 Total property, plant and equipment 9,613 9,072 Less: accumulated depreciation 3,016 2,868 Property, plant and equipment, net $6,597 $6,204 (a)Represents land held for future use and non-utility property. Average Service Life Percentage by Asset Category 2015 2014 2013 Electric—transmission and distribution 2.62% 2.96% 2.91% Gas 2.50% 2.47% 2.36% Common—electric and gas 10.35% 9.49% 8.45% 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 14—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 the second quarter of each year, Generation updates the long-term fundamental energy prices, which includes athorough evaluation of key assumptions including gas prices, load growth, environmental policy, plant retirements and renewable growth. In 2015, the year over year change in fundamentals did not indicate any impairments. In 2014, the year over year change in fundamentalssuggested that the carrying value of certain merchant wind assets may be impaired. Generation concluded that the estimated undiscounted futurecash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014.As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65million and a pre-tax impairment charge of $86 million was recorded within Operating and maintenance expense in Exelon’s and Generation’sConsolidated Statements of Operations and Comprehensive Income. In 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects with marketprice exposure for either all or a portion of the life of the 297 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) asset may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of eleven wind projects, primarilylocated in West Texas and Minnesota, were less than their respective carrying values at September 30, 2013. As a result, long-lived assets heldand used with a carrying amount of approximately $75 million were written down to their fair value of $32 million and a pre-tax impairment charge of$43 million, net of the impairment amount attributable to noncontrolling interests for certain of the projects, was recorded within Operating andmaintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. During 2015 and 2014, significant declines in oil and gas prices suggested that the carrying value of certain Upstream assets may beimpaired. Generation concluded that the estimated undiscounted future cash flows and fair value of various Upstream properties, primarily locatedin Oklahoma and Texas, were less than their respective carrying values at December 31, 2015 and 2014. As a result, pre-tax impairment chargesof $5 million and $124 million were recorded for the years ended December 31, 2015 and 2014, respectively, within Operating and maintenanceexpense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. After reflecting the impairmentcharges, Generation has $187 million of Upstream assets remaining on its Consolidated Balance Sheets at December 31, 2015. Further declinesin 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. 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 within Operating and maintenance expense on Exelon’s andGeneration’s Consolidated Statements of Operations and Comprehensive Income. See Note 4—Mergers, Acquisitions, and Dispositions for furtherinformation on asset sales. 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, Exelon and Generation recorded a pre-tax charge to Operatingand maintenance expense and Interest expense within their Statements of Operations and Comprehensive Income of approximately $111 millionand $8 million, respectively, to accrue remaining costs and reverse the previously capitalized costs. 298Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 15—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 exposure to residual value risk will not be mitigated by paymentsunder the service contract in this remaining period. In 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion forall rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term ofthe 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 the second quarters of 2015 and 2014, the estimated residual value of Exelon’s direct financingleases for the Georgia generating stations experienced other than temporary declines given increases in estimated long-term operating andmaintenance costs in the 2015 annual review and reduced long-term energy and capacity price expectations in the 2014 annual review. As aresult, Exelon recorded $24 million pre-tax impairment charges in both 2015 and 299Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2014 for these stations. These impairment charges were recorded within Investments and Operating and maintenance expense in Exelon’sConsolidated Balance Sheets and the Consolidated Statements of Operations and Comprehensive Income, respectively. Changes in theassumptions described above could potentially result in future impairments of Exelon’s direct financing lease investments, which could bematerial. Through December 31, 2015, no events have occurred that would require Exelon to review the estimated residual values of its directfinancing lease investments subsequent to the review performed in the second quarter of 2015. At December 31, 2015 and 2014, the components of the net investment in long-term leases were as follows: December 31, 2015 December 31, 2014 Estimated residual value of leased assets $639 $685 Less: unearned income 287 324 Net investment in long-term leases $352 $361 9. Implications of Potential Early Plant Retirements (Exelon and Generation) Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors thatwill continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacityauctions, potential legislative solutions in New York and Illinois such as the proposed Low Carbon Portfolio Standard (LCPS) legislation, the impactof final rules from the EPA requiring reduction of carbon and other emissions and the efforts of the states to implement those final rules, and theoutcome of the Ginna RSSA hearing and settlement procedures and the resulting contractual terms and conditions. On September 10, 2015, afterconsidering the results of the recent PJM capacity auctions, Exelon and Generation decided to defer decisions about the future operations of itsQuad Cities and Byron nuclear plants and will offer both plants in the 2019/2020 auction in May 2016. As a result of clearing the other PJMcapacity auction in September 2015 for the 2017/2018 transitional capacity auction, Exelon and Generation will continue to operate its Quad Citiesnuclear power plant through at least May 2018. The Byron plant is already obligated to operate through May 2019. On October 29, 2015, Exelonand Generation announced the deferral of any decision about the future operations of its Clinton nuclear plant and plans to bid the plant into theMISO capacity auction for the 2016-2017 planning year in April 2016. This decision was driven by MISO’s acknowledgment of the need for marketdesign changes to ensure long-term power system reliability in southern Illinois, the desire to provide Illinois policy makers with additional time toconsider needed reforms as well as the potential long-term impact of EPA’s Clean Power Plan. Exelon and Generation previously committed tocease operation of the Oyster Creek nuclear plant by the end of 2019. Exelon and Generation have not made any decisions regarding potentialnuclear plant closures at other sites at this time. As a result of a decision to early retire one or more other nuclear plants, certain changes in accounting treatment would be triggered andExelon’s and Generation’s results of operations and cash flows could be materially affected by a number of items including, among other items:accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flightcapital projects, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, relocation, retention, etc.),accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioningtrust funds. In addition, any early plant retirement would also result in reduced 300Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 costs, lower fuel expense, and lower capital expenditures in the periods beyond shutdown. While there are a number of Generation’snuclear plants that are at risk of early retirement, the following table provides the balance sheet amounts as of December 31, 2015 for significantassets and liabilities associated with the three nuclear plants currently considered by management to be at the greatest risk of early retirement dueto their current economic valuations and other factors: (in millions) Quad Cities Clinton Ginna Total Asset Balances Materials and supplies inventory $50 $57 $29 $136 Nuclear fuel inventory, net 218 107 60 385 Completed plant, net 1,030 579 127 1,736 Construction work in progress 11 9 11 31 Liability Balances Asset retirement obligation (698) (401) (644) (1,743) NRC License Renewal Term 2032 2046 2029 (a)Assumes Clinton seeks and receives a 20-year operating license renewal extension. In the event a decision is made to retire early one or more nuclear plants, the precise timing of the retirement date, and resulting financialstatement impact, is uncertain and would be influenced by a number of factors such as the results of any transmission system reliability studyassessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors.However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity obligations and just priorto its next scheduled nuclear refueling outage date in that year. 10. 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, 2015 and 2014 were as follows: Nuclear Generation Fossil FuelGeneration Transmission Other Quad Cities PeachBottom Salem Nine MilePoint Unit 2 Wyman PA DE/NJ Other Operator Generation Generation PSEGNuclear Generation FP&L FirstEnergy PSEG Ownership interest 75.00% 50.00% 42.59% 82.00% 5.89% Various 42.55% 44.24% Exelon’s share at December 31, 2015: Plant $1,035 $1,345 $566 $756 $3 $15 $65 $1 Accumulated depreciation 309 368 167 42 3 7 35 1 Construction work in progress 11 18 40 56 — — — — Exelon’s share at December 31, 2014: Plant $995 $1,095 $531 $676 $3 $14 $64 $2 Accumulated depreciation 266 343 150 14 3 7 34 1 Construction work in progress 15 133 29 48 — — — — (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, 2015and 2014. 301(a)(a) (f)(b)(c)(d)(e)(e)(e)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) (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)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. 11. Intangible Assets (Exelon, Generation, ComEd and PECO) Goodwill Exelon’s, Generation’s and ComEd’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for theyears ended December 31, 2015 and 2014 were as follows: ComEd Generation Exelon Gross Amount AccumulatedImpairment Losses CarryingAmount GrossAmount CarryingAmount GrossAmount AccumulatedImpairmentLosses CarryingAmount Balance, January 1, 2014 $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 Impairment losses — — — — — — — — Balance, December 31, 2015 $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 302(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) information 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. 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 analysis and a market multiples analysis. The discounted cash flow analysis relies on asingle scenario reflecting “base case” or “best estimate” projected cash flows for ComEd’s business and includes an estimate of ComEd’s terminalvalue based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using anassumed perpetual annuity based on the entity’s residual cash flows. The discount rate is based on the generally accepted Capital Asset PricingModel and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of businessenterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value.Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions,projected operating and capital cash flows from ComEd’s business and the fair value of debt. Management performs a reconciliation of the sum ofthe estimated fair value of all Exelon reporting units to Exelon’s enterprise value based on its trading price to corroborate the results of thediscounted cash flow analysis and the market multiple analysis. 2015 and 2014 Goodwill Impairment Assessment. Pursuant to authoritative guidance, ComEd is required to test its goodwill forimpairment annually and more frequently if an event occurs or circumstances change that suggest an impairment is more likely than not. ComEdperforms its assessment as of November 1, of each year. For its 2015 and 2014 annual goodwill impairment assessments, ComEd qualitativelydetermined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform quantitativeassessments. As part of its qualitative assessments, ComEd evaluated, among other things, management’s best estimate of projected operatingand capital cash flows for ComEd’s business, as well as, changes in certain market conditions, including the discount rate and regulated utilitypeer company EBITDA multiples, while also considering the passing margin from its last quantitative assessment performed as of November 1,2013. 303Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Intangible Assets Exelon’s, Generation’s and ComEd’s other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities andOther deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2015: WeightedAverageAmortizationYears Gross AccumulatedAmortization Net Estimated amortization expense 2016 2017 2018 2019 2020 Exelon Software License Agreement 10.0 $95 $(6) $89 $10 $10 $10 $10 $10 Generation Unamortized Energy Contracts Exelon Wind 18.0 224 (69) 155 14 14 14 14 10 Antelope Valley 25.0 190 (20) 170 8 8 8 8 8 Constellation 1.5 1,499 (1,473) 26 (33) (21) 11 8 10 CENG 1.7 (97) 48 (49) (11) (15) (18) (15) (8) Integrys 2.4 5 2 7 5 1 1 — — Customer Relationships Constellation 12.4 214 (76) 138 18 18 18 17 17 Integrys 10.0 50 (6) 44 5 5 5 5 5 Trade Names Constellation 10.0 243 (103) 140 23 23 23 23 23 ComEd Chicago settlement—1999 agreement 21.8 100 (83) 17 3 3 3 4 4 Chicago settlement—2003 agreement 17.9 62 (44) 18 4 4 4 3 3 Total intangible assets $2,585 $(1,830) $755 $46 $50 $79 $77 $82 (a)On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The intangibleasset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.(b)Includes unamortized energy contract assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. Excludes $44 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 $3 million, $0 million, $2million, $3 million and $4 million for 2016, 2017, 2018, 2019 and 2020, respectively.(c)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.(d)In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 242 MW solar project under development in northern Los Angeles County, CAfrom First Solar, Inc.(e)On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Planof Merger. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations.(f)See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.(g)See Note 4—Mergers, Acquisitions, and Dispositions for additional information.(h)Excludes $12 million of other miscellaneous customer relationships that have been acquired. The estimated amortization for these miscellaneous customer relationships is $1million in each of the years from 2016 to 2020.(i)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 304(k)(a)(b)(c) (d)(e)(f)(g)(h)(e)(g)(e)(i)(j)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.(j)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.(k)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, 2015, 2014 and 2013: For the Year Ended December 31, Exelon Generation ComEd 2015 $76 $69 $7 2014 179 179 7 2013 478 550 7 (a)At Exelon, amortization of unamortized energy contracts totaling $22 million, $135 million and $430 million for the years ended December 31, 2015, 2014 and 2013, respectively,was recorded in Operating revenues or Purchase power and fuel expense within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation,amortization of unamortized energy contracts totaling $22 million, $135 million and $507 million for the years ended December 31, 2015, 2014 and 2013, respectively, wasrecorded in Operating revenues or Purchase power and fuel expense 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 Operating revenues or Purchase power and fuel expense within Exelon’s and Generation’s Consolidated Statement of Operationsand Comprehensive Income. 305(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015, and 2014, PECO had current AECs of $2 million and $13 million, respectively. PECO had no noncurrent AECs as ofDecember 31, 2015 and 2014. As of December 31, 2015, and 2014, Generation had current RECs of $251 million and $191 million, respectively,and $56 million and $44 million of noncurrent REC’s, respectively. As of December 31, 2015 and 2014, ComEd had current RECs of $5 million and$4 million, respectively. ComEd had no noncurrent RECs as of December 31, 2015 and 2014. See Note 3—Regulatory Matters and Note 23—Commitments and Contingencies for additional information on RECs and AECs. 306Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 12. 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, 2015 and 2014: Exelon December 31, 2015 December 31, 2014 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Short-term liabilities $536 $3 $533 $— $536 $463 $463 Long-term debt (including amounts duewithin one year) 25,145 931 23,644 1,349 25,924 21,014 22,936 Long-term debt to financing trusts 641 — — 673 673 641 648 SNF obligation 1,021 — 818 — 818 1,021 833 Generation December 31, 2015 December 31, 2014 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Short-term liabilities $29 $— $29 $— $29 $36 $36 Long-term debt (including amounts due within one year) 8,959 — 7,767 1,349 9,116 8,196 8,822 SNF obligation 1,021 — 818 — 818 1,021 833 ComEd December 31, 2015 December 31, 2014 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Short-term liabilities $294 $— $294 $— $294 $304 $304 Long-term debt (including amounts due within one year) 6,509 — 7,069 — 7,069 5,925 6,788 Long-term debt to financing trusts 205 — — 213 213 205 213 PECO December 31, 2015 December 31, 2014 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Long-term debt (including amounts due within one year) $2,580 $— $2,786 $— $2,786 $2,232 $2,537 Long-term debt to financing trusts 184 — — 195 195 184 199 307(a)(b)(a)(a)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 December 31, 2014 CarryingAmount Fair Value CarryingAmount FairValue Level 1 Level 2 Level 3 Total Short-term liabilities $213 $3 $210 $— $213 $123 $123 Long-term debt (including amounts due within one year) 1,858 — 2,044 — 2,044 1,932 2,178 Long-term debt to financing trusts 252 — — 264 264 252 236 (a)Includes unamortized debt issuance costs of $180 million, $70 million, $38 million, $15 million and $9 million for Exelon, Generation, ComEd, PECO and BGE, respectively, atDecember 31, 2015 and $150 million, $70 million, $33 million, $14 million and $10 million at December 31, 2014.(b)Includes unamortized debt issuance costs of $7 million, $1 million and $6 million for Exelon, ComEd and BGE, respectively, at both December 31, 2015 and 2014. 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 nonrecourse debt (Level 3) is based on market and quoted prices for its ownand other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used todetermine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantlyimpact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fairvalue of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that issimilar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates arederived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a quarterly basis and the carrying value approximates fair value (Level 2).Generation also has tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investordemand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the creditspreads that are used to obtain the fair value as described above. 308(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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. 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 liquidate 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, 2015 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for ZionStation decommissioning, Rabbi trust investments, and deferred compensation obligations. 309Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014: Generation Exelon As of December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents $104 $— $— $104 $5,766 $— $— $5,766 Nuclear decommissioning trust fund investments Cash equivalents 219 92 — 311 219 92 — 311 Equities 3,008 1,894 — 4,902 3,008 1,894 — 4,902 Fixed income Corporate debt — 1,824 242 2,066 — 1,824 242 2,066 U.S. Treasury and agencies 1,323 15 — 1,338 1,323 15 — 1,338 Foreign governments — 61 — 61 — 61 — 61 State and municipal debt — 326 — 326 — 326 — 326 Other — 537 — 537 — 537 — 537 Fixed income subtotal 1,323 2,763 242 4,328 1,323 2,763 242 4,328 Middle market lending — — 428 428 — — 428 428 Private equity — — 125 125 — — 125 125 Real estate — — 35 35 — — 35 35 Other — 216 — 216 — 216 — 216 Nuclear decommissioning trust fund investments subtotal 4,550 4,965 830 10,345 4,550 4,965 830 10,345 Pledged assets for Zion Station decommissioning Cash equivalents — 17 — 17 — 17 — 17 Equities 1 5 — 6 1 5 — 6 Fixed income U.S. Treasury and agencies 6 2 — 8 6 2 — 8 Corporate debt — 46 — 46 — 46 — 46 Other — 1 — 1 — 1 — 1 Fixed income subtotal 6 49 — 55 6 49 — 55 Middle market lending — — 127 127 — — 127 127 Pledged assets for Zion Station decommissioning subtotal 7 71 127 205 7 71 127 205 Rabbi trust investments in mutual funds 17 — — 17 48 — — 48 Commodity derivative assets Economic hedges 1,922 3,467 1,707 7,096 1,922 3,467 1,707 7,096 Proprietary trading 36 64 30 130 36 64 30 130 Effect of netting and allocation of collateral (1,964) (2,629) (564) (5,157) (1,964) (2,629) (564) (5,157) Commodity derivative assets subtotal (6) 902 1,173 2,069 (6) 902 1,173 2,069 Interest rate and foreign currency derivative assets Derivatives designated as hedging instruments — — — — — 25 — 25 Economic hedges — 20 — 20 — 20 — 20 Proprietary trading 10 5 — 15 10 5 — 15 Effect of netting and allocation of collateral (3) (3) — (6) (3) (3) — (6) Interest rate and foreign currency derivative assets subtotal 7 22 — 29 7 47 — 54 Other investments — — 33 33 — — 33 33 Total assets 4,679 5,960 2,163 12,802 10,372 5,985 2,163 18,520 Liabilities Commodity derivative liabilities Economic hedges (2,382) (3,348) (850) (6,580) (2,382) (3,348) (1,097) (6,827) Proprietary trading (33) (57) (37) (127) (33) (57) (37) (127) Effect of netting and allocation of collateral 2,440 3,186 765 6,391 2,440 3,186 765 6,391 Commodity derivative liabilities subtotal 25 (219) (122) (316) 25 (219) (369) (563) Interest rate and foreign currency derivative liabilities — — Derivatives designated as hedging instruments — (16) — (16) — (16) — (16) Economic hedges — (3) — (3) — (3) — (3) Proprietary trading (12) — — (12) (12) — — (12) Effect of netting and allocation of collateral 12 3 — 15 12 3 — 15 Interest rate and foreign currency derivative liabilities subtotal — (16) — (16) — (16) — (16) Deferred compensation obligation — (30) — (30) — (99) — (99) Total liabilities 25 (265) (122) (362) 25 (334) (369) (678) Total net assets $4,704 $5,695 $2,041 $12,440 $10,397 $5,651 $1,794 $17,842 310(a)(b)(c)(d)(e)(f)(g)(g)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Assets Cash equivalents $405 $— $— $405 $1,119 $— $— $1,119 Nuclear decommissioning trust fund investments Cash equivalents 208 37 — 245 208 37 — 245 Equities 3,035 2,207 — 5,242 3,035 2,207 — 5,242 Fixed income Corporate debt — 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 fund investments 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 decommissioning subtotal 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 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 assets subtotal 1 17 — 18 1 22 — 23 Other investments — — 3 3 2 — 3 5 Total assets 4,558 6,742 2,029 13,329 5,305 6,747 2,029 14,081 Liabilities Commodity derivative liabilities Economic hedges (2,241) (3,458) (788) (6,487) (2,241) (3,458) (995) (6,694) Proprietary trading (195) (295) (42) (532) (195) (295) (42) (532) Effect of netting and allocation of collateral 2,416 3,557 729 6,702 2,416 3,557 729 6,702 Commodity derivative liabilities subtotal (20) (196) (101) (317) (20) (196) (308) (524) Interest rate and foreign currency derivative liabilities — — Derivatives designated as hedging instruments — (12) — (12) — (41) — (41) Economic hedges — (2) — (2) — (103) — (103) Proprietary trading (14) (9) — (23) (14) (9) — (23) Effect of netting and allocation of collateral 25 10 — 35 25 29 — 54 Interest rate and foreign currency derivative liabilities subtotal 11 (13) — (2) 11 (124) — (113) Deferred compensation obligation — (31) — (31) — (107) — (107) Total liabilities (9) (240) (101) (350) (9) (427) (308) (744) Total net assets $4,549 $6,502 $1,928 $12,979 $5,296 $6,320 $1,721 $13,337 311(a)(b)(c)(d)(e)(f)(g)(g)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.(b)Includes $52 million and $43 million of cash received from outstanding repurchase agreements at December 31, 2015 and 2014, respectively, and is offset by an obligation torepay upon settlement of the agreement as discussed in (d) below.(c)Includes derivative instruments of $(8) million and $(10) million, which have a total notional amount of $1,236 million and $794 million at December 31, 2015 and 2014,respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not representthe amount of the company’s exposure to credit or market loss.(d)Excludes net liabilities of $(3) million and $(5) million at December 31, 2015 and 2014, respectively. These items consist of receivables related to pending securities sales, interestand dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term innature with durations generally of 30 days or less.(e)Excludes net assets of $1 million and $3 million at December 31, 2015 and 2014, respectively. These items consist of receivables related to pending securities sales, interest anddividend receivables, and payables related to pending securities purchases.(f)Excludes $36 million and $35 million of cash surrender value of life insurance investment at December 31, 2015 and 2014, respectively, at Exelon Consolidated. Excludes $13million and $11 million of cash surrender value of life insurance investment at December 31, 2015 and 2014, respectively, at Generation.(g)Collateral posted to/(received from) counterparties totaled $476 million, $557 million and $201 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives,respectively, as of December 31, 2015. Collateral posted to/(received from) counterparties totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 andLevel 3 mark-to-market derivatives, respectively, as of December 31, 2014. ComEd, PECO and BGE The following tables present assets and liabilities measured and recorded at fair value on the utility Registrants’ Consolidated BalanceSheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2015 and 2014: ComEd PECO BGE As of December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents $29 $— $— $29 $271 $— $— $271 $25 $— $— $25 Rabbi trust investments in mutualfunds — — — — 8 — — 8 4 — — 4 Total assets 29 — — 29 279 — — 279 29 — — 29 Liabilities Deferred compensation obligation — (8) — (8) — (12) — (12) — (4) — (4) Mark-to-market derivative liabilities — — (247) (247) — — — — — — — — Total liabilities — (8) (247) (255) — (12) — (12) — (4) — (4) Total net assets (liabilities) $29 $(8) $(247) $(226) $279 $(12) $— $267 $29 $(4) $— $25 312(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 mutualfunds — — — — 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 (a)At PECO, excludes $12 million and $14 million of the cash surrender value of life insurance investments at December 31, 2015 and 2014, respectively.(b)The Level 3 balance includes the current and noncurrent liability of $23 million and $224 million, respectively, at December 31, 2015, and $20 million and $187 million,respectively, at December 31, 2014, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. 313(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014: Generation ComEd Exelon For The Year EndedDecember 31, 2015 NuclearDecommissioningTrust FundInvestments PledgedAssets forZion StationDecommissioning Mark-to-MarketDerivatives OtherInvestments TotalGeneration Mark-to-MarketDerivatives Eliminated inConsolidation Total Balance as of January 1, 2015 $691 $184 $1,050 $3 $1,928 $(207) $— $1,721 Total realized / unrealized gains (losses) Included in net income 4 — 22 1 27 — — 27 Included in noncurrent payables to affiliates 23 — — — 23 — (23) — Included in payable for Zion Stationdecommissioning — (2) — — (2) — — (2) Included in regulatory assets/liabilities — — — — — (40) 23 (17) Change in collateral — — 29 — 29 — — 29 Purchases, sales, issuances and settlements Purchases 226 20 144 30 420 — — 420 Sales (8) (75) (25) — (108) — — (108) Settlements (106) — — — (106) — — (106) Transfers into Level 3 4 — 80 — 84 — — 84 Transfers out of Level 3 (4) — (249) (1) (254) — — (254) Balance as of December 31, 2015 $830 $127 $1,051 $33 $2,041 $(247) $— $1,794 The amount of total gains included in incomeattributed to the change in unrealized gains(losses) related to assets and liabilities as ofDecember 31, 2015 $4 $— $856 $— $860 $— $— $860 314 (b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2014 NuclearDecommissioningTrust FundInvestments Pledged Assetsfor Zion StationDecommissioning Mark-to-MarketDerivatives OtherInvestments TotalGeneration Mark-to-MarketDerivatives 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 othercomprehensive income — — — — — — — — Included in noncurrentpayables to affiliates 14 — — — 14 — (14) — Included in payable forZion 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 gainsincluded in income attributedto the change in unrealizedgains (losses) related toassets and liabilities held asof December 31, 2014 $4 $— $640 $— $644 $— $— $644 (a)Includes a reduction for the reclassification of $834 million and $114 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2015and 2014, respectively.(b)Includes $55 million of decreases in fair value and an increase for realized losses due to settlements of $(15) million recorded in purchased power expense associated withfloating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2015. Includes $13 million of decreases in fair value and a reduction forrealized gains due to settlements of $1 million for the year ended December 31, 2014.(c)Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition. 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, 2015 and 2014: Generation Exelon OperatingRevenues PurchasedPower andFuel Other,net OperatingRevenues PurchasedPower andFuel Other,net Total gains (losses) included in net income for the yearended December 31, 2015 $67 $(45) $4 $67 $(45) $4 Change in the unrealized gains (losses) relating to assetsand liabilities held for the year ended December 31,2015 $858 $(2) $4 $858 $(2) $4 315(d) (b)(a)(c)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 (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 NDT fund investments policies outline investment guidelines for the trusts and limit the trustfunds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or lesswhen purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair valuemeasurements hierarchy as Level 1 or Level 2. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from directfeeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trustfunds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on theNew York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume tradingrequirements 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. Withrespect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental pricesource or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine thatanother price source is considered to be preferable. Generation has obtained an understanding of how these prices are 316(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fairvalues of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade ina highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluatedprices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and arecategorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using athird party valuation that contains significant unobservable inputs and are categorized in Level 3. Equity, balanced and fixed income commingled funds and mutual funds are maintained by investment companies and hold certaininvestments in accordance with a stated set of fund objectives such as holding short term fixed income securities or tracking the performance ofcertain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of thesefunds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and havebeen categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the fund administrators value the funds usingNAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities. Theseinvestments typically can be redeemed monthly with 30 or less days of notice and without further restrictions, and, as a result are categorized asLevel 2. 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. Middle market lending are investments in loans or managed funds which lend to 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 and real estate investments include those in limited partnerships that invest in operating companies and real estate holdingcompanies that are not publicly traded on a stock exchange, such as,leveraged buyouts, growth capital, venture capital, distressed investments,investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estateinvestments is determined using NAV or its equivalent as a practical expedient. These investments typically cannot be redeemed and aregenerally liquidated over a period of 8 to 10 years from the initial investment date. Private equity and real estate valuations are reported by thefund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discountedfuture cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. Since these valuationinputs are not highly observable, private equity and real estate investments have been categorized as Level 3. As of December 31, 2015, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, privateequity investments, and real estate investments of approximately $266 million. These commitments will be funded by Generation’s existingnuclear decommissioning trust funds. 317Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as ofDecember 31, 2015. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, typeof industry, foreign country, and individual fund. As of December 31, 2015, there were no significant concentrations (generally defined as greaterthan 10 percent) of risk in Generation’s NDT assets. See Note 16—Asset Retirement Obligations for further discussion on the NDT fund investments. Rabbi Trust Investments (Exelon, Generation, PECO and BGE). The Rabbi trusts were established to hold assets related to deferredcompensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets areincluded in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of mutual funds and life insurance policies. Themutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which areconsistent with Exelon’s overall investment strategy. Mutual funds are publicly quoted and have been categorized as Level 1 given the clearobservability of the prices. The life insurance policies are valued using the cash surrender value of the policies, which is provided by a third party.The cash surrender value inputs are not observable. 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 13—Derivative Financial Instruments for further discussion on mark-to-market derivatives. 318Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 underlying notional investments are comprised primarily of equities, mutual funds,commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferredcompensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd) Mark-to-Market Derivatives (Exelon, Generation, ComEd). For valuations that include both observable and unobservable inputs, if 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 executive officer and includesthe chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chiefexecutive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the riskmanagement activities. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified bythe middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation ofderivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformancerisk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk werenot 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 and certain transmission congestion contracts. Generation utilizes various inputs and factors including marketdata and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in theinputs 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 319Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect thecredit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodityprice varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and HenryHub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generallyshorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forwardcurve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does nottypically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements andnot a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spreadcalculated across all Level 3 power and gas delivery locations is approximately $2.91 and $0.27 for power and natural gas, respectively. Many ofthe commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though thecontract as a whole must be classified as Level 3. See ITEM 7A.—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKfor information regarding the maturity by year of the Registrant’s mark-to-market derivative assets and liabilities. On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for theprocurement of long-term renewable energy and associated RECs. See Note 13—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, 2015 ValuationTechnique UnobservableInput Range Mark-to-market derivatives—Economic hedges (Generation) $857 DiscountedCash Flow Forward powerprice $11 - $88 Forward gasprice $1.18 - $8.95 Option Model Volatilitypercentage 5% - 152% Mark-to-market derivatives—Proprietary trading(Generation) $(7) DiscountedCash Flow Forward powerprice $13 - $78 Mark-to-market derivatives (ComEd) $(247) DiscountedCash Flow Forward heatrate 9x - 10x Marketabilityreserve 3.5% - 7% Renewablefactor 87% - 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. 320(a)(c)(d)(d)(a)(c)(d)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 fair values do not include cash collateral posted on level three positions of $201 million as of December 31, 2015.(d)Unlike the previous year, the New England region was not a significant driver for the upper end of the ranges for power and gas as of December 31, 2015. 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 gasprice $1.52 - $14.02 Option Model Volatilitypercentage 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 posted 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. 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, real estate and private equity investments the fair value is determined using acombination of valuation models including cost models, market models and income models. The valuation estimates are based on valuations ofcomparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfoliocompany or its assets, considering offers from third parties to buy the portfolio company, its historical and projected 321(a)(c)(d)(d)(a)(c)(d)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiumsapplied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance. Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for thevaluations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is notreasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs.Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performedprocedures to assess the reasonableness of the valuations. For a sample of its Level 3 investments, Generation reviewed independent valuationsand reviewed the assumptions in the detailed pricing models used by the fund managers. 13. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange rate risk, and interest rate riskrelated to ongoing business operations. Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE) To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generationare exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ establishedpolicies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financialderivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy andenergy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigateexposure to fluctuations in commodity prices. 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 23—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. 322Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 derivative and non-derivative instruments to manage the commodity price risk of itselectric generation facilities, including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacityagreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-pricederivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fueland energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level thatprovides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of powerplants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactionshedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors.Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units.This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value arerecognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned andcontracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. Asof December 31, 2015, the proportion of expected generation hedged for the major reportable segments was 90%-93%, 60%-63% and 28%-31%for 2016, 2017, and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expectedgeneration. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contractedfor capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to marketquotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges andcertain non-derivative contracts, including Generation’s sales to ComEd, PECO and BGE to serve their retail load. 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. 323Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 price risk related to electricsupply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contractsand block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNSscope 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 2015 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 the2015 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 324Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, which included settled physical sales volumes of 7,310 GWh, 10,571 GWh and 8,762 GWh for the years endedDecember 31, 2015, 2014 and 2013, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’srevenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes. 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 utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition,the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cashflow hedges. These strategies are employed to manage interest rate risks. At December 31, 2015, Exelon had $800 million of notional amounts offixed-to-floating hedges outstanding and Exelon and Generation had $738 million of notional amounts of floating-to-fixed hedges outstanding.Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated withunhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in an approximately $6 million decrease inExelon Consolidated pre-tax income for the year ended December 31, 2015. To manage foreign exchange rate exposure associated withinternational energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typicallydesignated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of December 31, 2015: Generation Other Exelon Description DerivativesDesignatedas HedgingInstruments EconomicHedges ProprietaryTrading CollateralandNetting Subtotal DerivativesDesignatedas HedgingInstruments EconomicHedges CollateralandNetting Subtotal Total Mark-to-market derivativeassets (current assets) $— $10 $10 $(5) $15 $— $— $— $— $15 Mark-to-market derivativeassets (noncurrent assets) — 10 5 (1) 14 25 — — 25 39 Total mark-to-market derivativeassets — 20 15 (6) 29 25 — — 25 54 Mark-to-market derivativeliabilities (current liabilities) (8) (2) (9) 11 (8) — — — — (8) Mark-to-market derivativeliabilities (noncurrentliabilities) (8) (1) (3) 4 (8) — — — — (8) Total mark-to-market derivativeliabilities (16) (3) (12) 15 (16) — — — — (16) Total mark-to-market derivativenet assets (liabilities) $(16) $17 $3 $9 $13 $25 $— $— $25 $38 (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)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 accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms ofnon-cash collateral. These are not reflected in the table above. 325 (a) (b) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 interest rate and foreign exchange hedge balances recorded by the Registrants as ofDecember 31, 2014: Generation Other Exelon Description DerivativesDesignatedas HedgingInstruments EconomicHedges ProprietaryTrading CollateralandNetting Subtotal DerivativesDesignatedas HedgingInstruments EconomicHedges CollateralandNetting Subtotal Total Mark-to-market derivativeassets (current assets) $7 $7 $20 $(22) $12 $3 $— $— $3 $15 Mark-to-market derivativeassets (noncurrent assets) 1 5 7 (7) 6 20 1 (19) $2 $8 Total mark-to-market derivativeassets 8 12 27 (29) 18 23 1 (19) 5 23 Mark-to-market derivativeliabilities (current liabilities) (8) (2) (14) 25 1 — — — — 1 Mark-to-market derivativeliabilities (noncurrentliabilities) (4) — (9) 10 (3) (29) (101) 19 (111) (114) Total mark-to-market derivativeliabilities (12) (2) (23) 35 (2) (29) (101) 19 (111) (113) Total mark-to-market derivativenet assets (liabilities) $(4) $10 $4 $6 $16 $(6) $(100) $— $(106) $(90) (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)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 accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms ofnon-cash collateral. These are not reflected in the table above. 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, Income Statement Location 2015 2014 2013 2015 2014 2013 Gain (Loss) on Swaps Gain (Loss) on Borrowings Generation Interest expense $(1) $(16) $(15) $— $2 $(6) Exelon Interest expense $2 $3 $(24) $(9) $15 $(3) (a)For the years ended December 31, 2015 and 2014, the loss on Generation swaps included $(1) million and $(17) million realized in earnings, respectively, with an immaterialamount and $4 million excluded from hedge effectiveness testing, respectively. 326 (a) (b) (b) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with aderivative asset of $25 million. At December 31, 2014, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interestrate swaps of $1,450 million and $550 million, with a derivative asset of $29 million and $7 million, respectively. During the years endedDecember 31, 2015 and 2014, the impact on the results of operations, as a result of the ineffectiveness from fair value hedges, was a $17 milliongain and $18 million gain, respectively. Cash Flow Hedges. During 2014, Exelon entered into $400 million of floating-to-fixed forward starting interest rate swaps to manage a portionof the interest rate exposure associated with the anticipated refinancing of existing debt. The swaps are designated as cash flow hedges. InJanuary 2015, in connection with Generation’s $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated these swaps. As theoriginal forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments areprobable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon’sConsolidated Statement of Operations and Comprehensive Income. 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 14—Debt and Credit Agreements for additionalinformation regarding the financing. The swaps have a notional amount of $500 million as of December 31, 2015 and expire in 2019. The swap wasdesignated as a cash flow hedge in the fourth quarter of 2014. At December 31, 2015, the subsidiary had a $12 million derivative liability related tothe swap. 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 14—Debt and Credit Agreements foradditional information regarding the financing. The swaps have a notional amount of $189 million as of December 31, 2015 and expire in 2020. Theswaps are designated as cash flow hedges. At December 31, 2015, the subsidiary had a $2 million derivative liability related to the swaps. During the years ended December 31, 2015 and 2014, the impact on the results of operations as a result of ineffectiveness from cash flowhedges in continuing designated hedge relationships were immaterial. Economic Hedges. During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation, entered into floating-to-fixed interestrate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14—Debt and CreditAgreements for additional information regarding the financing. The swaps have a total notional amount of $25 million as of December 31, 2015 andexpire in 2027. After the closing of the Constellation merger, the swaps were re-designated as cash flow hedges. During the first quarter of 2015,the swaps were de-designated as the forecasted transaction was no longer probable of occurring. All future changes in fair value are reflected inInterest expense. At December 31, 2015, the subsidiary had a $2 million derivative liability related to these swaps, which included an immaterialamount that was amortized to Interest expense after de-designation. 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 14—Debt and Credit Agreements foradditional information 327Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) regarding the financing. The swap has a notional amount of $24 million as of December 31, 2015, and expires in 2030. This swap was designatedas a cash flow hedge. During the first quarter of 2015, the swaps were de-designated as the forecasted transaction was no longer probable ofoccurring. All future changes in fair value are reflected in Interest expense. At December 31, 2015, the derivative asset related to the swap wasimmaterial. During the second quarter 2015, upon the issuance of debt, Exelon terminated $2,400 million of floating-to-fixed forward starting interest rateswaps. As a result of the termination of the swaps, Exelon realized a $64 million loss during the second quarter of 2015. At December 31, 2015, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge riskassociated with the interest rate component of commodity positions and $30 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, 2015 and 2014, $3 millionand $8 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. 328Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015: Generation ComEd Exelon Derivatives EconomicHedges ProprietaryTrading CollateralandNetting Subtotal EconomicHedges TotalDerivatives Mark-to-marketderivative assets (current assets) $5,236 $108 $(3,994) $1,350 $— $1,350 Mark-to-marketderivative assets (noncurrent assets) 1,860 22 (1,163) 719 — 719 Total mark-to-marketderivative assets 7,096 130 (5,157) 2,069 — 2,069 Mark-to-marketderivative liabilities (current liabilities) (4,907) (94) 4,827 (174) (23) (197) Mark-to-marketderivative liabilities (noncurrent liabilities) (1,673) (33) 1,564 (142) (224) (366) Total mark-to-marketderivative liabilities (6,580) (127) 6,391 (316) (247) (563) Total mark-to-marketderivative net assets (liabilities) $516 $3 $1,234 $1,753 $(247) $1,506 (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 $352 million and $180 million, respectively, and current and noncurrent liabilities are shown net of collateral of $480million and $222 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,234 million atDecember 31, 2015.(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. 329(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Collateraland Netting 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 $599million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million atDecember 31, 2014.(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. As of December 31,2015, no unrealized balance remains in accumulated OCI to be reclassified by Generation. 330 (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014,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 hedged transactions, result in the ultimaterecognition of net revenues or expenses at the contractual price. Income StatementLocation Total Cash Flow Hedge OCI Activity,Net of Income Tax Generation Exelon Total CashFlowHedges TotalCash FlowHedges Accumulated OCI derivative gain at January 1, 2014 $114 $120 Effective portion of changes in fair value (15) (31) Reclassifications from accumulated OCI to net income Operating revenues (117) (117) Accumulated OCI derivative gain at December 31, 2014 (18) (28) Effective portion of changes in fair value (8) (12) Reclassifications from accumulated OCI to net income Other, net — 16 Reclassifications from accumulated OCI to net income Interest expense 7 7 Reclassifications from accumulated OCI to net income Operating revenues (2) (2) Accumulated OCI derivative gain at December 31, 2015 $(21) $(19) (a)Amount is net of related income tax expense of $78 million for the year ended December 31, 2014.(b)Amount is net of related income tax benefit of $10 million for the year ended December 31, 2015.(c)Amount is net of related income tax expense of $4 million for the year ended December 31, 2015. During the years ended December 31, 2015, 2014, and 2013, 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 $2 million, $195 million and $683 million pre-tax gain,respectively. In addition, the effect of Exelon’s former energy-related cash flow hedge activity impact on pre-tax earnings based on thereclassification adjustment from Accumulated OCI to earnings was a $2 million, $195 million and $464 million pre-tax gain for the years endedDecember 31, 2015, 2014 and 2013, respectively. Given that the cash flow hedges had primarily consisted of forward power sales and powerswaps and did not include power and gas options or sales, neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness infuture periods relating to energy-related hedge positions as all were de-designated prior to the merger date. 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 331(a)(a)(b)(c)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 U.S. Dollars. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipatedfuture debt issuance related to the proposed PHI merger. For the years ended December 31, 2015, 2014 and 2013, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in Operating revenues or Purchased power and fuel expense, orInterest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fairvalue changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fairvalue” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement”represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period. Generation IntercompanyEliminations ExelonCorporate Exelon Year Ended December 31, 2015 OperatingRevenues PurchasedPowerand Fuel InterestExpense Total Operating Revenues InterestExpense Total Change in fair value of commodity positions $759 $(355) $— $404 $— $— $404 Reclassification to realized at settlement of commodity positions (563) 409 — (154) — — (154) Net commodity mark-to-market gains (losses) 196 54 — 250 — — 250 Change in fair value of treasury positions 13 — — 13 — 36 49 Reclassification to realized at settlement of treasury positions (6) — — (6) — 64 58 Net treasury mark-to market gains (losses) 7 — — 7 — 100 107 Net mark-to market gains (losses) $203 $54 $— $257 $— $100 $357 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 of commodity positions 231 (223) — 8 — — 8 Net commodity mark-to-market gains (losses) (182) (417) — (599) — — (599) Change in fair value of treasury positions 10 — (2) 8 — (100) (92) Reclassification to realized at settlement of treasury positions (2) — — (2) — — (2) Net treasury mark-to market gains (losses) 8 — (2) 6 — (100) (94) Net mark-to market gains (losses) $(174) $(417) $(2) $(593) $— $(100) $(693) 332(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 PurchasedPower and Fuel InterestExpense Total Operating Revenues InterestExpense Total Change in fair value of commodity positions $286 $180 $— $466 $(6) $— $460 Reclassification to realized at settlement of commodity positions (64) 104 — 40 13 — 53 Net commodity mark-to-market gains (losses) 222 284 — 506 7 — 513 Change in fair value of treasury positions (1) — (4) (5) — — (5) Reclassification to realized at settlement of treasury positions (1) — — (1) — — (1) Net treasury mark-to market gains (losses) (2) — (4) (6) — — (6) Net mark-to market gains (losses) $220 $284 $(4) $500 $7 $— $507 (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, 2015, 2014, and 2013 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 related to derivatives” in Exelon’s and Generation’sConsolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contractsheld at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified torealized due to settlement of the derivative during the period. Location on IncomeStatement For the Years EndedDecember 31, 2015 2014 2013 Change in fair value of commodity positions Operating Revenues $8 $(1) $(22) Reclassification to realized at settlement of commodity positions Operating Revenues (14) (29) (15) Net commodity mark-to-market gains (losses) Operating Revenues (6) (30) (37) Change in fair value of treasury positions Operating Revenues 8 1 1 Reclassification to realized at settlement of treasury positions Operating Revenues (10) 3 (3) Net treasury mark-to market gains (losses) Operating Revenues (2) 4 (2) Net mark-to market gains (losses) Operating Revenues $(8) $(26) $(39) 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 333(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterpartyagainst amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to eachindividual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements existwith a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s creditdepartment establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivativecontracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of ascoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that acounterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enablingagreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individualand 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, 2015. 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 $15 million, $36 million and $31 million, respectively. Rating as of December 31, 2015 TotalExposureBefore CreditCollateral CreditCollateral NetExposure Number ofCounterpartiesGreater than 10%of Net Exposure Net Exposure ofCounterpartiesGreater than 10%of Net Exposure Investment grade $1,397 $50 $1,347 1 $432 Non-investment grade 67 25 42 — — No external ratings Internally rated—investment grade 521 — 521 — — Internally rated—non-investment grade 77 7 70 — — Total $2,062 $82 $1,980 1 $432 Net Credit Exposure by Type of Counterparty December 31, 2015 Financial institutions $187 Investor-owned utilities, marketers, power producers 886 Energy cooperatives and municipalities 872 Other 35 Total $1,980 (a)As of December 31, 2015, credit collateral held from counterparties where Generation had credit exposure included $13 million of cash and $69 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 334(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If theforward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion afteradjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers representsComEd’s net credit exposure. As of December 31, 2015, ComEd’s net credit exposure to suppliers was immaterial. ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk 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, 2015, PECO had no net credit exposure to 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. 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, 2015, PECO’s credit exposure under its natural gas supply and assetmanagement agreements with investment grade suppliers was immaterial. 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, 2015, BGE had no net credit exposure to suppliers. 335Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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’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, 2015, BGE had credit exposure of $4 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 demand. In this case, Generation believes an amount of several monthsof future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, whichhas 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 2015 2014 Gross Fair Value of Derivative Contracts Containing this Feature $(932) $(1,433) Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements 684 1,140 Net Fair Value of Derivative Contracts Containing This Feature $(248) $(293) (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. 336 (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 had cash collateral posted of $1,267 million and letters of credit posted of $497 million, and cash collateral held of $21 million andletters of credit held of $78 million as of December 31, 2015 for external counterparties with derivative positions. Generation had cash collateralposted of $1,497 million and letters of credit posted of $672 million and cash collateral held of $77 million and letters of credit held of $24 million atDecember 31, 2014 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ byS&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $2.0 billion and $2.4 billion as of December 31, 2015and 2014, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative andnon-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, 2015, Generation’s and Exelon’s swaps were in an asset position, with a fair value of $13 million and$38 million, respectively. See Note 25—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 rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certainunsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided fromsuppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limitsoutlined in the contracts. As of December 31, 2015, ComEd held no collateral from suppliers in association with energy procurement contracts.Under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition,under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. TheREC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As ofDecember 31, 2015, 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, 2015, PECO was not required to post collateral for any ofthese agreements. If PECO lost its investment grade credit rating as of December 31, 2015, PECO could have been required to postapproximately $25 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. 337Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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’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, 2015, BGE was not required to post collateral for any of theseagreements. If BGE lost its investment grade credit rating as of December 31, 2015, BGE could have been required to post approximately $35million of collateral to its counterparties. 14. 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, 2015 and 2014: MaximumProgram Size atDecember 31, OutstandingCommercialPaper atDecember 31, Average Interest Rate onCommercial Paper Borrowings forthe Year Ended December 31, Commercial Paper Issuer 2015 2014 2015 2014 2015 2014 Exelon Corporate $500 $500 $— $— n.a. n.a. Generation 5,450 5,600 — — 0.49% 0.32% ComEd 1,000 1,000 294 304 0.53% 0.33% PECO 600 600 — — n.a. n.a. BGE 600 600 210 120 0.48% 0.29% Total $8,150 $8,300 $504 $424 (a)Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $275 million and $200 million bilateral agreements for Generationas of December 31, 2015 and 2014, respectively) that backstop the commercial paper program. See discussion and Credit Facilities table below for items affecting effectiveprogram size.(b)Excludes additional credit facilities 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. The agreements for these facilities expired on October 16,2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of creditissued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively. 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 outstanding commercial paper does notreduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding thethen available capacity under its credit facility. 338(a)(b)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacityunder their respective credit facilities: Available Capacity atDecember 31, 2015 Borrower Aggregate BankCommitment Facility Draws OutstandingLetters of Credit Actual To SupportAdditionalCommercialPaper Exelon Corporate $500 $— $26 $474 $474 Generation 5,725 — 1,449 4,276 4,174 ComEd 1,000 — 2 998 704 PECO 600 — 1 599 599 BGE 600 — — 600 390 Total $8,425 $— $1,478 $6,947 $6,341 (a)Excludes additional credit facilities 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. The agreements for these facilities expired on October 16,2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of creditissued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.(b)Excludes $275 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, 2015, 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 2015, 2014 and 2013. PECOdid not have any short-term borrowings during 2015, 2014 or 2013. Exelon 2015 2014 2013 Average borrowings $499 $571 $254 Maximum borrowings outstanding 739 1,164 682 Average interest rates, computed on a daily basis 0.53% 0.32% 0.37% Average interest rates, at December 31 0.88% 0.53% 0.35% Generation 2015 2014 2013 Average borrowings $1 $93 $42 Maximum borrowings outstanding 50 552 291 Average interest rates, computed on a daily basis 0.49% 0.32% 0.32% Average interest rates, at December 31 n.a. n.a. n.a. 339(a) (c)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015 2014 2013 Average borrowings $461 $415 $203 Maximum borrowings outstanding 684 597 446 Average interest rates, computed on a daily basis 0.53% 0.33% 0.40% Average interest rates, at December 31 0.89% 0.50% 0.37% BGE 2015 2014 2013 Average borrowings $37 $64 $35 Maximum borrowings outstanding 210 180 135 Average interest rates, computed on a daily basis 0.48% 0.29% 0.31% Average interest rates, computed at December 31 0.87% 0.61% 0.31% Credit Agreements On October 23, 2015, the credit agreement for CENG’s $100 million bilateral credit facility was amended and extended for an additional twoyears. This facility has been utilized by CENG to fund working capital and capital projects. This facility does not back Generation’s commercialpaper program. On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility, scheduled to mature inJanuary of 2019. This facility does not back Generation’s commercial paper program. Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s and BGE’s revolving credit facilities bear interest at a rate basedupon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular registrant’s credit rating. Exelon Corporate, Generation,ComEd, PECO and BGE have adders of 27.5, 27.5, 7.5, 0.0 and 0.0 basis points for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and100.0 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basispoints and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregatecommitments. The fee varies depending upon the respective credit ratings of the borrower. An event of default under any of the Registrants’ credit agreements would not constitute an event of default under any of the otherRegistrants’ credit agreements, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principalamount in excess of $100 million in the aggregate by Generation under its credit agreement would constitute an event of default under the ExelonCorporation credit agreement. 340Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Each credit agreement requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certainchanges in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt ofits project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year endedDecember 31, 2015: Exelon Generation ComEd PECO BGECredit agreement threshold 2.50 to 1 3.00 to 1 2.00 to 1 2.00 to 1 2.00 to 1 At December 31, 2015, the interest coverage ratios at the Registrants were as follows: Exelon Generation ComEd PECO BGE Interest coverage ratio 9.77 12.31 7.25 8.94 10.66 341Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and2014: Exelon MaturityDate December 31, Rates 2015 2014 Long-term debt Rate stabilization bonds 5.72% — 5.82% 2017 $120 $195 First mortgage bonds 1.20% — 6.45% 2016-2045 9,019 8,079 Senior unsecured notes 1.55% — 7.60% 2017-2045 9,803 7,071 Unsecured bonds 2.80% — 6.35% 2016-2036 1,750 1,750 Pollution control notes 2.50% — 2.70% 2025-2036 435 — Nuclear fuel procurement contracts 3.15% — 3.35% 2018-2020 127 70 Notes payable and other 1.43% — 7.83% 2016-2053 314 174 Junior subordinated notes 6.50% 2024 1,150 1,150 Contract payment - junior subordinated notes 2.50% 2017 64 108 Long-term software licensing agreement 3.95% 2024 111 — Nonrecourse debt: Fixed rates 2.29% — 6.00% 2031-2037 1,162 1,166 Variable rates 2.42% — 5.00% 2017-2030 1,058 1,101 Total long-term debt 25,113 20,864 Unamortized debt discount and premium, net (63) (37) Unamortized debt issuance costs (180) (150) Fair value adjustment 275 333 Fair value hedge carrying value adjustment, net — 4 Long-term debt due within one year (1,500) (1,802) Long-term debt $23,645 $19,212 Long-term debt to financing trusts Subordinated debentures to ComEdFinancing 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 Unamortized debt issuance costs (7) (7) Long-term debt to financing trusts $641 $641 (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 capital lease obligations of $29 million and $32 million at December 31, 2015 and 2014, respectively. Lease payments of $4 million, $4 million, $4 million, $5 million, $4million, and $8 million will be made in 2016, 2017, 2018, 2019, 2020 and thereafter, respectively.(c)Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2—Variable Interest Entities for additional information).The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2015, $100 million was outstanding.(d)Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1—SignificantAccounting Policies for additional information. 342(a)(b)(c)(d)(e)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. Generation MaturityDate December 31, Rates 2015 2014 Long-term debt Senior unsecured notes 2.00% — 7.60% 2017-2042 $5,971 $5,771 Pollution control notes 2.50% — 2.70% 2025-2036 435 — Nuclear fuel procurement contracts 3.15% — 3.35% 2018-2020 127 70 Notes payable and other 1.43% — 7.83% 2016-2035 166 26 Nonrecourse debt: Fixed rates 2.29% — 6.00% 2031-2037 1,162 1,166 Variable rates 2.42% — 5.00% 2017-2030 1,058 1,101 Total long-term debt 8,919 8,134 Fair value adjustment 127 146 Unamortized debt discount and premium, net (17) (14) Unamortized debt issuance costs (70) (70) Long-term debt due within one year (90) (614) Long-term debt $8,869 $7,582 (a)Includes Generation’s capital lease obligations of $21 million and $24 million at December 31, 2015 and 2014, respectively. Generation will make lease payments of $4 million, $4million, $4 million, $5 million and $4 million in 2016, 2017, 2018, 2019, 2020, respectively. The capital lease matures in 2020.(b)Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2 - Variable Interest Entities for additional information).The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2015, $100 million was outstanding.(c)Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - SignificantAccounting Policies for additional information. ComEd MaturityDate December 31, Rates 2015 2014 Long-term debt First mortgage bonds 1.95% — 6.45% 2016-2045 $6,419 $5,829 Notes payable and other 6.95% — 7.49% 2016-2053 148 148 Total long-term debt 6,567 5,977 Unamortized debt discount and premium, net (20) (19) Unamortized debt issuance costs (38) (33) Long-term debt due within one year (665) (260) Long-term debt $5,844 $5,665 Long-term debt to financing trust Subordinated debentures to ComEd Financing III 6.35% 2033 $206 $206 Total long-term debt to financing trusts 206 206 Unamortized debt issuance costs (1) (1) Long-term debt to financing trusts $205 $205 343(a)(b)(c)(a) (b)(c)(d)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture.(b)Includes ComEd’s capital lease obligations of $8 million at both December 31, 2015 and 2014, respectively. Lease payments of less than $1 million will be made from 2016through expiration at 2053.(c)Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1—SignificantAccounting Policies for additional information.(d)Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. PECO MaturityDate December 31, Rates 2015 2014 Long-term debt First mortgage bonds 1.20% — 5.95% 2016-2044 $2,600 $2,250 Total long-term debt 2,600 2,250 Unamortized debt discount and premium, net (5) (4) Unamortized debt issuance costs (15) (14) Long-term debt due within one year (300) — Long-term debt $2,280 $2,232 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)Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1—SignificantAccounting Policies for additional information.(c)Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. BGE MaturityDate December 31, Rates 2015 2014 Long-term debt Rate stabilization bonds 5.72% — 5.82% 2017 $120 $195 Senior unsecured notes 2.80% — 6.35% 2016-2036 1,750 1,750 Total long-term debt 1,870 1,945 Unamortized debt discount and premium, net (3) (3) Unamortized debt issuance costs (9) (10) Long-term debt due within one year (378) (75) Long-term debt $1,480 $1,857 Long-term debt to financing trusts Subordinated debentures to BGE Capital Trust II 6.20% 2043 $258 $258 Total long-term debt to financing trusts 258 258 Unamortized debt issuance costs (6) (6) Long-term debt to financing trusts $252 $252 344(a)(b)(c)(a)(b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1—SignificantAccounting Policies for additional information.(b)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 2016 through 2020 and thereafter are as follows: Year Exelon Generation ComEd PECO BGE 2016 $1,487 $90 $665 $300 $378 2017 1,841 805 425 — 42 2018 1,393 53 840 500 — 2019 973 673 300 — — 2020 3,311 1,911 500 — — Thereafter 16,756 5,387 4,043 1,984 1,708 Total $25,761 $8,919 $6,773 $2,784 $2,128 (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. PHI Merger Financing 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. In June 2015, the remaining $3.2 billion bridge credit facility was terminated as a result ofExelon’s issuance of $4.2 billion of long-term debt to fund a portion of the purchase price and related costs and expenses for the pending PHImerger and for general corporate purposes. In connection with the $4.2 billion issuance of Senior Unsecured Notes in 2015, the tranches due in 2025, 2035, and 2045 had to beredeemed at the principal amount plus a 1% premium of principal on December 31, 2015, if the PHI merger was not consummated or terminatedprior to such date (“Special Mandatory Redemption”). Exelon also had the option to redeem those notes earlier at a 1% premium of principal, ifExelon determined that the merger would not be completed before December 31, 2015. On October 29, 2015, Exelon commenced a private exchange offer (Exchange Offer) to certain eligible holders whereby, for those that tookpart, the outstanding Senior Unsecured Notes in the 2025, 2035 and 2045 tranches were exchanged for new Senior Unsecured Notes. The newSenior Unsecured Notes have substantially the same terms as the outstanding Senior Unsecured Notes, except the outside date with regard to thespecial redemption provisions is June 30, 2016, (or the date the PHI merger is terminated if earlier), rather than December 31, 2015, and undercertain circumstances, can be further extended to August 31, 2016. On December 2, 2015, Exelon exchanged $1.9 billion of the Senior Unsecured Notes and paid a consent fee of approximately $5 million,which has been deferred on Exelon’s Consolidated Balance 345(a)(b)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Sheet and $4 million of third-party debt issuance costs, which were charged to earnings within Other, net on Exelon’s Consolidated Statement ofOperations and Comprehensive Income. On December 2, 2015, Exelon also redeemed $0.9 billion of Senior Unsecured Notes not exchanged inthe Exchange Offer resulting in the payment of $9 million of redemption premium and the acceleration of the unamortized original issuancediscount and deferred financing costs associated with the redeemed debt of $9 million, which were charged to earnings within Other, net onExelon’s Consolidated Statement of Operations and Comprehensive Income. 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 merger and related costs and expenses for the pending PHI merger and for general corporate purposes. Each equity unit representsan undivided beneficial ownership interest in Exelon’s 2.50% junior subordinated notes due in 2024 and a forward equity purchase contract whichsettles in 2017. The junior subordinated notes are expected to be remarketed in 2017. 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 (“Contract Payment Obligation”) were recorded to Long-term debt,representing the obligation to make contract payments, with an offsetting reduction to Common stock. The obligation for the contract payments isaccreted to interest expense over the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income.During 2015, contract payments of $44 million related to the Contract Payment Obligation were included within Retirements of long-term debt inExelon’s Consolidated Statements of Cash Flows. During 2014, the Contract Payment Obligation was considered a non-cash financing transactionthat was excluded from Exelon’s Consolidated Statements of Cash Flows. Until settlement of the equity purchase contract, earnings per sharedilution resulting from the equity unit issuance will be determined under the treasury stock method. Nonrecourse Debt Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.4 billion of generating assets and $0.2 billion ofUpstream gas properties have been pledged as collateral at December 31, 2015. Borrowings under these agreements are secured by the assetsand equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement to finance a solar construction project inDenver, Colorado. The agreement is scheduled to mature on June 30, 2031. The agreement bears interest at a fixed rate of 5.50% annually withinterest payable annually. As of December 31, 2015, $7 million was outstanding. CEU Upstream. In July 2011, Generation entered into a 5-year asset-based lending agreement associated with certain Upstream gasproperties that it owns. The borrowing base committed under the facility is $85 million as of December 31, 2015. The commitment level can bedecreased if the assets no longer support the current borrowing base, which would result in repayment of a portion or all of the outstandingbalance. The commitment can be increased up to $500 million if the assets support a 346Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) higher borrowing base and Generation is able to obtain additional commitments from lenders. Calculations of the borrowing base are impacted byprojected production and commodity prices. The facility was amended and extended through January 2019. The agreement bears interest at avariable rate equal to LIBOR plus 2.50% and is payable monthly. As of December 31, 2015, $68 million was outstanding under the facility. 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 is scheduled to mature on December 31, 2030. The note bears interest at a variable rate equal toLIBOR plus 2.25% and is payable quarterly. As of December 31, 2015, $33 million was outstanding. The subsidiary also executed interest rateswaps with an initial notional value of $30 million at an interest rate of 3.57% in order to convert the variable interest payments to fixed paymentson 75% of the $41 million facility amount, as required by the debt covenants. See Note 13—Derivative Financial Instruments for additionalinformation regarding interest rate swaps. Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $11 million solar loan agreement related to a solarconstruction project in Holyoke, Massachusetts. The agreement is scheduled to mature on December 2031. The agreement bears interest at afixed rate of 5.25% annually with interest payable monthly. As of December 31, 2015, $10 million was outstanding. 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 were fixed upon each advance at aspread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and theoutstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2015, $574 million was outstanding.In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2015, Generation had $69million in letters of credit outstanding related to the project. 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 scheduled to mature on September 7, 2030. The notebears interest at a variable rate equal to LIBOR plus 2.25% with interest payable quarterly. As of December 31, 2015, $32 million was outstanding.The subsidiary also executed interest rate swaps for an initial notional amount of $29 million at an interest rate of 2.03% in order to convert thevariable interest payments to fixed payments on 75% of the $38 million facility amount, as required by the debt covenants. See Note 13—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 senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho,Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for itsgeneral business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interestpayable semi-annually. As of December 31, 2015, $572 million was outstanding. 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, 2015, the Continental Windletter of credit facility had $99 million in letters of credit outstanding related to the project. 347Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) ExGen Renewables I. In February 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. The proceeds were distributed to Generation for its generalbusiness purposes. The loan is scheduled to mature on February 6, 2021. The loan bears interest at a variable rate equal to LIBOR plus 4.25%,subject to a 1% LIBOR floor with interest payable quarterly. EGR indirectly owns Continental Wind. As of December 31, 2015, $258 million wasoutstanding. In addition to the financing, EGR entered into interest rate swaps with an initial notional amount of $240 million at an interest rate of2.03% to manage a portion of the interest rate exposure in connection with the financing. See Note 13—Derivative Financial Instruments foradditional information regarding interest rate swaps. ExGen Texas Power. In September 2014, ExGen Texas Power, LLC (EGTP), an indirect subsidiary of Exelon and Generation, issued$675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for generalbusiness purposes. The loan is scheduled to mature on September 18, 2021. The term loan bears interest at a variable rate equal to LIBOR plus4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2015, $666 million was outstanding. As part of theagreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18,2019. In addition to the financing, EGTP entered into interest rate swaps with an initial notional amount of approximately $505 million at an interestrate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 13—Derivative Financial Instruments for additional information regarding interest rate swaps. 15. 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, 2015 Exelon Generation ComEd PECO BGE Included in operations: Federal Current $407 $546 $(80) $64 $25 Deferred 566 16 310 69 126 Investment tax credit amortization (22) (19) (2) — (1) State Current (86) (90) 7 (10) — Deferred 208 49 45 20 39 Total $1,073 $502 $280 $143 $189 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 348Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 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, 2015 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 3.7 1.0 4.9 1.0 5.3 Qualified nuclear decommissioning trust fund loss (0.4) (0.8) — — — Domestic production activities deduction (0.7) (1.3) — — — Health care reform legislation — — — — 0.1 Amortization of investment tax credit, including deferred taxes on basisdifference (0.9) (1.5) (0.3) (0.1) (0.1) Plant basis differences (1.5) — (0.1) (8.7) (0.7) Production tax credits and other credits (1.9) (3.4) — — — Non-controlling interest 0.3 0.5 — — — Statute of limitations expiration (1.4) (2.4) — — — Other — — 0.2 0.2 — Effective income tax rate 32.2% 27.1% 39.7% 27.4% 39.6% 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 — — — Domestic production activities deduction (2.0) (4.1) — — — Health care reform legislation 0.1 — 0.2 — 0.2 Amortization of investment tax credit, including deferred taxes on basisdifference (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 (0.2) (1.1) 0.3 0.1 (0.2) Effective income tax rate 26.8% 16.9% 39.6% 24.5% 39.9% 349Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 — — — Domestic production activities deduction — — — — — Health care reform legislation 0.1 — 0.7 — 0.2 Amortization of investment tax credit, including deferred taxes on basisdifference (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 (0.3) 0.4 0.3 (0.3) (0.9) Effective income tax rate 37.6% 36.7% 37.9% 29.1% 39.0% The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as ofDecember 31, 2015 and 2014 are presented below: For the Year Ended December 31, 2015 Exelon Generation ComEd PECO BGE Plant basis differences $(13,393) $(4,269) $(4,424) $(2,901) $(1,821) Accrual based contracts (136) (136) — — — Derivatives and other financial instruments (203) (181) (4) — — Deferred pension and postretirement obligation 1,801 (371) (505) (9) (47) Nuclear decommissioning activities (592) (592) — — — Deferred debt refinancing costs 133 48 (15) (1) (4) Regulatory assets and liabilities (1,706) — (219) 16 (264) Tax loss carryforward 103 56 — — 33 Tax credit carryforward 327 374 — — — Investment in CENG (595) (595) — — — Other, net 1,112 425 270 105 27 Deferred income tax liabilities (net) $(13,149) $(5,241) $(4,897) $(2,790) $(2,076) Unamortized investment tax credits (622) (598) (17) (2) (5) Total deferred income tax liabilities (net) and unamortized investment taxcredits $(13,771) $(5,839) $(4,914) $(2,792) $(2,081) 350Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Plant basis differences $(12,143) $(3,834) $(3,945) $(2,749) $(1,660) 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) $(1,906) 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) $(1,911) The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2015. Exelon Generation ComEd PECO BGE Federal Federal general business credits carryforward 416 415 — — — State State net operating losses and other credit carryforwards 2,086 1,259 — — 618 Deferred taxes on state tax attributes (net) 117 66 — — 34 Valuation allowance on state tax attributes 13 11 — — 1 (a)Exelon’s federal general business credit carryforwards will expire beginning in 2032.(b)Exelon’s and Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2016.(c)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, 2015, 2014 and 2013: Exelon Generation ComEd PECO BGE Unrecognized tax benefits at January 1, 2015 $1,829 $1,357 $149 $44 $— Increases based on tax positions related to 2015 108 — — — 106 Change to positions that only affect timing (705) (659) (7) (44) — Increases based on tax positions prior to 2015 79 65 — — 14 Decreases based on tax positions prior to 2015 (116) (112) — — — Decrease from settlements with taxing authorities (31) (31) — — — Decreases from expiration of statute of limitations (86) (86) — — — Unrecognized tax benefits at December 31, 2015 $1,078 $534 $142 $— $120 351(a)(b)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 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 $— Included in Exelon’s unrecognized tax benefits balance at December 31, 2015 and 2014 are approximately $540 million and $1,129 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. 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 disallowed AmerGen’s claims. In early 2009, Generation filed a complaint in theUnited States Court of Federal Claims to contest this determination. 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. On March 11, 2015, the Federal Circuit affirmed the lower court’s decision to deny AmerGen’s claims for refund. Exelon will not bepursuing further appeals with respect to this issue and, as a result, reduced Generation and PECO’s unrecognized tax benefits by a total of $661million and $43 million, respectively, in the first quarter of 2015. This change in unrecognized tax benefits had no impact on Exelon, Generation, orPECO’s effective tax rate. Unrecognized tax benefits that if recognized would affect the effective tax rate Exelon and Generation have $538 million and $509 million, respectively, of unrecognized tax benefits at December 31, 2015 that, ifrecognized, would decrease the effective tax rate. BGE has 352Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) $120 million of unrecognized tax benefits at December 31, 2015 that, if recognized, may be included in future base rates and that portion wouldhave no impact to the effective tax rate. Exelon and Generation had $701 million and $672 million, respectively, of unrecognized tax benefits atDecember 31, 2014 that, if recognized, would decrease the effective tax rate. In 2015, the unrecognized tax benefits decreased at Exelon andGeneration due to settlements with state tax authorities and the expiration of statues of limitations for certain state jurisdictions. Reasonably possible that total amount of unrecognized tax benefits could significantly increase or decrease within 12 months afterthe reporting date Like-Kind Exchange As of December 31, 2015, Exelon and ComEd have approximately $397 million and $142 million of unrecognized tax benefits that couldsignificantly decrease within the 12 months after the reporting date as a result of a decision in the like-kind exchange litigation described below.Exelon and ComEd have unrecognized tax benefits that, if recognized, would decrease Exelon’s effective tax rate by $69 million and increaseComEd’s effective tax rate by $11 million. Settlement of Income Tax Audits and Litigation As of December 31, 2015, Exelon, Generation, and BGE have approximately $174 million, $54 million, and $120 million of unrecognizedstate tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potentialsettlements, and expected statute of limitation expirations. Of the above unrecognized tax benefits, Exelon and Generation have $54 million that,if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to BGE, if recognized, may be included in future baserates and that portion would have no impact to the effective tax rate. 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, 2015 $(288) $80 $(210) $3 $(1) December 31, 2014 (310) 40 (203) 3 (1) 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, 2015 $(13) $(31) $7 $— $— December 31, 2014 (36) (50) 6 — 1 December 31, 2013 391 17 281 (1) — 353Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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, 2001-2014 Exelon and subsidiaries Illinois unitary income tax returns 2007-2014 Constellation combined New York corporate income tax returns 2010-March 2012 Various separate company Pennsylvania corporate net income tax returns 2010-2014 BGE Maryland corporate net income tax returns 2011-2014 Various Exelon Maryland corporate net income tax returns 2012-2014 Various Constellation (Non-BGE) Maryland corporate net income tax returns 2011-2014 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 deferred by reinvesting a portion of the proceeds from the sale in qualifying replacementproperty under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interestsin three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this positionand asserted that the entire gain of approximately $1.2 billion was taxable in 1999. Exelon has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has assertedthat Exelon’s 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 354Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) subsequent to December 31, 2012, it is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013,Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) andincremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful inlitigation. Of this amount, approximately $172 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorableimpacts of the after-tax interest amounts on ComEd’s equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013,a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the unpaid taxliabilities related to the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annualoperating earnings of Exelon or ComEd. In addition, ComEd will continue to record non-cash equity contributions from Exelon in the amount of thenet after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it isunlikely that the IRS’s assertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded. 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 and the trial took place in August of 2015. Exelon was not required to remitany part of the asserted tax or penalty in order to litigate the issue. While the Tax Court could reach its decision as early as 2016, the litigationcould take three to five years if an appeal is necessary. Decisions in the Tax Court are not controlled by the Federal Circuit’s decision inConsolidated Edison. 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. In connection with the termination, Exelon deposited $65million with the IRS, including $35 million by ComEd. The deposit can be redesignated to any tax year, if necessary, and may be used to satisfyany amounts owed as a result of the litigation. In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, the potential tax and after-tax interest, net of thedeposit discussed above and exclusive of penalties, that could become currently payable as of December 31, 2015 may be as much as $760million, of which approximately $280 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless.Interest will continue to accrue until such time as payment is made. An appeal of an adverse decision in the Tax Court would necessitate eitherthe posting of a bond or the payment of the tax and interest for the tax years before the court. A final appellate decision could take several years. 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 changed its method of accounting for deducting repairs in accordance with this guidancebeginning in the 2014 tax year. The adoption of the new method resulted in Generation recording a cash tax detriment of approximately $120million in 2014. Long-Term State Tax Apportionment (Exelon and Generation) The long-term state tax apportionment was revised in the fourth quarter of 2015 pursuant to Exelon’s long-term state tax apportionmentpolicy, resulting in the recording of a deferred state tax 355Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) expense for Exelon and Generation of $41 million (net of Federal taxes) and $11 million (net of Federal taxes), respectively. In 2014, in accordancewith the policy, Exelon and Generation recorded a deferred state tax benefit of $28 million (net of Federal taxes) and $40 million (net of Federaltaxes), 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 net benefit attributable to Exelonis reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2015,Generation, PECO, and BGE recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $57 million, $16million, and $7 million respectively. ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as aresult of a tax net operating loss. During 2014, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $55million and $25 million, respectively. ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax SharingAgreement 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. 16. 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. 356Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2014 to December 31, 2015: Exelon andGeneration Nuclear decommissioning ARO at January 1, 2014 $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 Accretion expense 387 Net increase due to changes in, and timing of, estimated future cash flows 901 Costs incurred to decommission retired plants (3) Nuclear decommissioning ARO at December 31, 2015 $8,246 (a)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.(b)Includes $7 million and $8 million as the current portion of the ARO at December 31, 2015 and 2014, respectively, which is included in Other current liabilities on Exelon’s andGeneration’s Consolidated Balance Sheets. During 2015, Generation’s total nuclear ARO increased by approximately $1.3 billion, reflecting impacts of ARO updates completed during2015 to reflect changes in amounts and timing of estimated decommissioning cash flows and impacts of year-to-date accretion of the ARO liabilitydue to the passage of time. The increase in the ARO during 2015 was primarily driven by an increase of approximately $630 million for costs expected to be incurred forrequired site security during the decommissioning periods in which SNF remains on-site and until major reactor components and buildings havebeen dismantled and removed. This projected increase is based on emerging industry experience at nuclear sites in the planning or early stage ofdecommissioning indicating greater than originally expected numbers of security personnel required to be on site during these decommissioningperiods. Generation will continue to monitor emerging security cost trends, including potential strategies to limit such costs by, for example,optimizing the transfer of SNF when DOE starts taking possession of SNF or increasing the use of dry SNF storage, and will adjust the AROliability accordingly. The 2015 increase in the ARO includes an increase of approximately $285 million for the impacts of a change implemented inthe 2015 annual assessment of Generation’s SNF storage and disposal cost estimation methodology to better align the projected timing of SNFtransfers to the DOE with assumed plant shutdown dates as well as higher assumed probabilities of early retirements of certain economicallychallenged nuclear plants (See Note 9—Implications of Potential Early Plant Retirements for additional information) and further accretion of theobligation. These increases were partially offset by reductions in estimated cost escalation rates, primarily for labor and energy costs. The financial statement impact related to the increase in the ARO due to the changes in, and timing of, estimated cash flows primarilyresulted in a corresponding increase in Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately$8 million of the 2015 adjustment resulted in a credit to income, which is included in Operating and maintenance expense within Exelon’s andGeneration’s Consolidated Statements of Operations and Comprehensive Income. 357(a) (b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 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. 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 from utility customers for anyof Generation’s other nuclear units. With respect to 358Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded toComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units.With respect to Generation’s other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection withCENG’s acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certainconditions pertaining to nuclear decommissioning trust funds that, if met, could possibly result in obligations to make payments to certain thirdparties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioningactivities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine MilePoint, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioningactivities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management anddecommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amountequal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers.Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities. At December 31, 2015, and 2014, Exelon and Generation had NDT fund investments totaling $10,342 million and $10,537 million,respectively. For additional information related to the NDT fund investments, refer to Note 12—Fair Value of Financial Assets and Liabilities. The following table provides unrealized gains on NDT funds for 2015, 2014 and 2013: Exelon and Generation For the Years Ended December 31, 2015 2014 2013 Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units $(282) $180 $406 Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units (197) 134 146 (a)Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s ConsolidatedBalance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.(b)Excludes $7 million, $29 million and $7 million of net unrealized gains related to the Zion Station pledged assets in 2015, 2014 and 2013, 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 (losses) 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 359 (a) (b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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 areexpected to exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gainsand losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s ConsolidatedStatements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement ofOperations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment tothe regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and correspondingregulatory liability. Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioningobligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations andComprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the ConsolidatedStatements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s results of operations and financialposition could be material. As of December 31, 2015, the NDT funds of each of the former ComEd units, except for Zion (see Zion StationDecommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making thisdetermination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum fundingobligation 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 26—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 Zion 360Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Station, 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. 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 $84 million, which is included within the nuclear decommissioningARO at December 31, 2015. 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, 2015 and 2014: Exelon and Generation 2015 2014 Carrying value of Zion Station pledged assets $206 $319 Payable to Zion Solutions 189 292 Current portion of payable to Zion Solutions 99 137 Cumulative withdrawals by Zion Solutions to pay decommissioning costs 786 666 (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.(c)Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings. 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 361 (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) decommissioning work according to an established schedule and constructed a dry cask storage facility on the land and has loaded the SNF fromthe SNF pools onto the dry cask storage facility at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the LeaseAgreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delaysin the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default byZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets areinsufficient. EnergySolutions and its parent company have also provided a performance guarantee and EnergySolutions has entered into otheragreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a specialpurpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station. 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, 2015 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, 2015 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 of6.1% to 6.3% (as compared to a historical 5-year annual average pre-tax return of approximately 7%). 362Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 making 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. 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 thathad been established in 2013. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequatedecommissioning funding assurance was in place for all reactors owned by Generation. During 2014, the operating license for Limerick Unit 1 wasextended by 20 years. As a result of this extension, and the subsequent funding assurance calculation performed by the NRC, it was found thatthe parent company guarantee was no longer required and thus the parent guarantee for Limerick Unit 1 has been cancelled effective March 13,2015. See Note 3—Regulatory Matters for additional information regarding the operating license extension for Limerick Unit 1. Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2015. This report reflects the status ofdecommissioning funding assurance as of December 31, 2014. Due to increased cost estimates received in the second half of 2014, BraidwoodUnit 1, Braidwood Unit 2, and Byron Unit 2 did not meet the NRC’s minimum funding assurance criteria as of December 31, 2014. NRC guidanceprovides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assuranceshortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewalfor Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on thesefunds on or before March 31, 2017. On February 4, 2016, Generation submitted an updated decommissioning funding status report with the NRCfor Braidwood Units 1 and 2, and Byron Unit 2. This report reflected the recently approved license renewals for these units, and showed that theyhave adequate decommissioning funding assurance, and that the shortfall identified in the March 31, 2015 report has now been resolved. Theincreased security costs discussed above will be taken into consideration, as appropriate and in accordance with the regulatory requirements, inGeneration’s future decommissioning funding status reports submitted to the NRC. Generation does not expect the increased costs to changeGeneration’s NRC minimum funding assurance status. 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 363Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. ComEd, PECO and BGEhave AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1—Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs. The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets fromJanuary 1, 2014 to December 31, 2015: Exelon Generation ComEd PECO BGE Non-nuclear AROs at January 1, 2014 $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 Net increase (decrease) due to changes in, and timing of, estimated future cashflows (10) (12) 6 (4) — Development projects 10 10 — — — Accretion expense 16 10 5 1 — Sale of generating assets (2) (2) — — — Payments (5) (3) (2) — — Non-nuclear AROs at December 31, 2015 $355 $197 $113 $27 $18 (a)During the year ended December 31, 2015, Generation recorded a decrease of $(2) million in Operating and maintenance expense. ComEd, PECO, and BGE did not record anyadjustments in Operating and maintenance expense for the year ended December 31, 2015. During the year ended December 31, 2014, Generation recorded a decrease of $(2)million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO and BGE did not record any adjustments in Operating and maintenanceexpense for the year ended December 31, 2014.(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)Represents AROs related to generating stations classified as held for sale. See Note 4—Mergers, Acquisitions, and Dispositions for further information.(e)Reflects a reduction to the ARO resulting primarily from the sales of Schuylkill generating station in 2015 and Keystone and Conemaugh generating stations in 2014. See Note 4—Mergers, Acquisitions, and Dispositions for further information.(f)Excludes $5 million, $2 million, $0 million and $1 million as the current portion of the ARO at December 31, 2015 for Generation, ComEd, PECO and BGE, respectively. Excludes$1 million, $1 million, $1 million and $1 million as the current portion of the ARO at December 31, 2014 for Generation, ComEd, PECO and BGE, respectively. This is included inOther current liabilities on the Registrants’ respective Consolidated Balance Sheets. 364 (a)(b) (c)(d)(e)(f) (a)(b) (c)(e)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) As of December 31, 2015, 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 other postretirement benefit plans in whichemployees of each operating company participated at December 31, 2015. Operating Company Name of Plan: Generation ComEd PECO BGE BSC Qualified Pension Plans: Exelon Corporation Retirement Program X X X X X Exelon Corporation Cash Balance Pension Plan X X X X X Exelon Corporation Pension Plan for Bargaining Unit Employees X X X Exelon New England Union Employees Pension Plan X Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek X X X X Pension Plan of Constellation Energy Group, Inc. X X X X X Pension Plan of Constellation Energy Nuclear Group, LLC X X X Nine Mile Point Pension Plan X X Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan Aand Plan B X Non-Qualified Pension Plans: Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess BenefitPlan X X X X Exelon Corporation Supplemental Management Retirement Plan X X X X X Constellation Energy Group, Inc. Senior Executive Supplemental Plan X X X Constellation Energy Group, Inc. Supplemental Pension Plan X X X Constellation Energy Group, Inc. Benefits Restoration Plan X X X X Constellation Nuclear Plan, LLC Executive Retirement Plan X X Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan X X Baltimore Gas & Electric Company Executive Benefit Plan X X X Baltimore Gas & Electric Company Manager Benefit Plan X X X X Other Postretirement Benefit Plans: PECO Energy Company Retiree Medical Plan X X X X X Exelon Corporation Health Care Program X X X X X Exelon Corporation Employees’ Life Insurance Plan X X X X X Constellation Energy Group, Inc. Retiree Medical Plan X X X X X Constellation Energy Group, Inc. Retiree Dental Plan X X X Constellation Energy Group, Inc. Employee Life Insurance Plan and Family LifeInsurance Plan X X X X X Constellation 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 X Retiree Dental Plan of Constellation Energy Nuclear Group LLC X X X Nine 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.(d)Employees generally remain in their legacy benefit plans when transferring between operating companies. 365 (d) (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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 OCI and regulatory assets (liabilities), in accordance with the applicable authoritative guidance. Themeasurement date for the plans is December 31. During the first quarter of 2015, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflectactual census data as of January 1, 2015. This valuation resulted in an increase to the pension obligation of $45 million and an increase to theother postretirement benefit obligation of $57 million. Additionally, Accumulated other comprehensive loss (AOCL) increased by approximately $27million (after tax), regulatory assets increased by approximately $48 million, and regulatory liabilities decreased by approximately $11 million. The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all planscombined: Pension Benefits OtherPostretirement Benefits 2015 2014 2015 2014 Change in benefit obligation: Net benefit obligation at beginning of year $18,256 $15,459 $4,197 $4,451 Service cost 326 293 119 117 Interest cost 710 749 167 186 Plan participants’ contributions — — 42 42 Actuarial (gain) loss (582) 2,095 (341) 502 Plan amendments — — (23) (1,012) Acquisitions/divestitures — 594 — 142 Curtailments — (8) — — Settlements (34) (30) — — Gross benefits paid (923) (896) (223) (231) Net benefit obligation at end of year $17,753 $18,256 $3,938 $4,197 Pension Benefits OtherPostretirement Benefits 2015 2014 2015 2014 Change in plan assets: Fair value of net plan assets at beginning of year $14,874 $13,571 $2,430 $2,238 Actual return on plan assets (32) 1,443 4 90 Employer contributions 462 332 40 291 Plan participants’ contributions — — 42 42 Gross benefits paid (923) (896) (223) (231) Acquisitions/divestitures — 454 — — Settlements (34) (30) — — Fair value of net plan assets at end of year $14,347 $14,874 $2,293 $2,430 366 (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)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 2015 2014 2015 2014 Other current liabilities $21 $16 $27 $25 Pension obligations 3,385 3,366 — — Non-pension postretirement benefit obligations — — 1,618 1,742 Unfunded status (net benefit obligation less net plan assets) $3,406 $3,382 $1,645 $1,767 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 2015 2014 Projected benefit obligation $17,753 $18,256 Fair value of net plan assets 14,347 14,874 ABO inexcess of plan assets 2015 2014 Projected benefit obligation $17,753 $18,256 Accumulated benefit obligation 16,792 17,191 Fair value of net plan assets 14,347 14,874 On a PBO basis, the plans were funded at 81% at December 31, 2015 compared to 81% at December 31, 2014. On an ABO basis, the planswere funded at 85% at December 31, 2015 compared to 87% at December 31, 2014. The ABO differs from the PBO in that the ABO includes noassumption about future compensation levels. 367Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Components of Net Periodic Benefit Costs The majority of the 2015 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 3.94%. The majority of the 2015 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.46% for funded plans and a discount rate of 3.92%. A portion of the net periodic benefit cost for all pensionand OPEB plans are capitalized within each of the Registrant’s Consolidated Balance Sheets. The following table presents the components ofExelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2015, 2014 and 2013. Pension Benefits OtherPostretirement Benefits 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $326 $293 $317 $119 $117 $162 Interest cost 710 749 650 167 186 194 Expected return on assets (1,026) (994) (1,015) (151) (154) (132) Amortization of: Prior service cost (credit) 13 14 14 (174) (122) (19) Actuarial loss 571 420 562 80 50 83 Settlement charges 2 2 9 — — — Net periodic benefit cost $596 $484 $537 $41 $77 $288 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, 2015, 2014 and 2013 for all plans combined. Pension Benefits OtherPostretirement Benefits 2015 2014 2013 2015 2014 2013 Changes in plan assets and benefit obligations recognized in AOCI andregulatory assets (liabilities): Current year actuarial loss (gain) $476 $1,639 $(1,169) $(194) $561 $(628) Amortization of actuarial loss (571) (420) (562) (80) (50) (83) Current year prior service (credit) cost — — — (23) (1,012) 15 Amortization of prior service (cost) credit (13) (14) (14) 174 122 19 Settlements (2) (2) (8) — — — Total recognized in AOCI and regulatory assets (liabilities) $(110) $1,203 $(1,753) $(123) $(379) $(677) (a)Of the $110 million gain related to pension benefits, $64 million and $46 million were recognized in AOCI and regulatory assets, respectively, during 2015. Of the $123 million gainrelated to other postretirement benefits, $63 million and $60 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2015. Of the $1,203 million lossrelated to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to otherpostretirement benefits, $162 million and $217 million were recognized 368 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized inAOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCIand regulatory assets, respectively, during 2013. 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, 2015 and 2014, respectively, for all plans combined: Pension Benefits OtherPostretirement Benefits 2015 2014 2015 2014 Prior service cost (credit) $36 $49 $(812) $(963) Actuarial loss 7,310 7,407 711 985 Total $7,346 $7,456 $(101) $22 (a)Of the $7,346 million related to pension benefits, $4,246 million and $3,100 million are included in AOCI and regulatory assets, respectively, at December 31, 2015. Of the $(101)million related to other postretirement benefits, $(63) million and $(38) million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2015. 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. The $22 millionrelated to other postretirement benefits is included in regulatory assets (liabilities) at December 31, 2014. The following table provides the components of Exelon’s AOCI and regulatory assets(liabilities) at December 31, 2015 (included in the tableabove) that are expected to be amortized as components of periodic benefit cost in 2016. These estimates are subject to the completion of anactuarial valuation of Exelon’s pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2016 andactual claims activity as of December 31, 2015. The valuation is expected to be completed in the first quarter of 2016 for the majority of thebenefit plans. Pension Benefits OtherPostretirement Benefits Prior service cost (credit) $13 $(175) Actuarial loss 501 50 Total $514 $(125) (a)Of the $514 million related to pension benefits at December 31, 2015, $290 million and $224 million are expected to be amortized from AOCI and regulatory assets in 2016,respectively. Of the $(125) million related to other postretirement benefits at December 31, 2015, $(64) million and $(61) million are expected to be amortized from AOCI andregulatory assets (liabilities) in 2016, 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. 369 (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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. 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 as of December 31, 2014, respectively. There were no changes to the mortality assumption in 2015. The following assumptions were used to determine the benefit obligations for the plans at December 31, 2015, 2014 and 2013. 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 2015 2014 2013 2015 2014 2013 Discount rate 4.29% 3.94% 4.80% 4.29% 3.92% 4.90% Rate ofcompensationincrease Mortality table RP-2000tableprojected to2012 withimprovementscale AA,withScale BB-2Dimprovements(adjusted) RP-2000tableprojected to2012 withimprovementscale AA,withScale BB-2Dimprovements(adjusted) RP-2000table withScale AAimprovements RP-2000tableprojected to2012 withimprovementscale AA,withScale BB-2Dimprovements(adjusted) RP-2000tableprojected to2012 withimprovementscale AA,withScale BB-2Dimprovements(adjusted) RP-2000table withScale AAimprovements Health care costtrend oncovered charges N/A N/A N/A 5.50%decreasing toultimate trendof 5.00% in2017 6.00%decreasing toultimate trendof 5.00% in2017 6.00%decreasing toultimate trendof 5.00% in2017 (a)3.25% through 2019 and 3.75% thereafter.(b)3.25% through 2018 and 3.75% thereafter. 370 (a) (a) (b) (a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2015,2014 and 2013: Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Discount rate 3.94% 4.80% 3.92% 3.92% 4.90% 4.00% Expected return on planassets 7.00% 7.00% 7.50% 6.50% 6.59% 6.45% Rate of compensationincrease Mortality table RP-2000tableprojected to2012 withimprovementscale AA,withScale BB-2Dimprovements(adjusted) RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements RP-2000tableprojected to2012 withimprovementscale AA,withScale BB-2Dimprovements(adjusted) RP-2000table withScale AAimprovements RP-2000table withScale AAimprovements Health care cost trend oncovered charges N/A N/A N/A 6.00%decreasing toultimate trendof 5.00% in2017 6.00%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, 2015. Discount rates for CENG’s legacy pension and OPEB plans ranged from 3.68%-4.14% and 4.32%-4.43%, respectively.(b)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 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 of the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control ofCENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5—Investment in Constellation Energy Nuclear Group, LLC for further information.(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, 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 remeasurements.(d)Not applicable to pension and other postretirement benefit plans that do not have plan assets.(e)3.25% through 2019 and 3.75% thereafter.(f)3.25% through 2018 and 3.75% thereafter.(g)3.25% through 2017 and 3.75% thereafter. 371(a)(b)(c)(a)(b)(c)(d)(d)(d)(d)(d)(d) (e) (f) (g) (e) (f) (g)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Assumed health care cost trend rates impact the other postretirement benefit plan costs reported for Exelon’s participant populations withplan 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 2015 total service and interest cost components $12 on postretirement benefit obligation at December 31, 2015 100 Effect of a one percentage point decrease in assumed health care cost trend: on 2015 total service and interest cost components (9) on postretirement benefit obligation at December 31, 2015 (89) 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, including a provision that imposes an excise tax on certain high-cost plans whereby premiums paid over a prescribedthreshold will be taxed at a 40% rate. Additional legislation was passed in December 2015 that made some changes to the law, including movingthe implementation date of the excise tax from 2018 to 2020. Although the excise tax does not go into effect until 2020, accounting guidancerequires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is stillunclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Certain key assumptions are required toestimate the impact of the excise tax on Exelon’s other postretirement benefit obligation, including projected inflation rates (based on the CPI).Exelon reflected its best estimate of the expected impact in its annual actuarial valuation. 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 2015 2014 2013 2015 2014 2013 Generation $231 $173 $119 $14 $124 $30 ComEd 143 122 118 7 125 4 PECO 40 11 11 — 5 20 BGE 1 — — 16 17 24 BSC 47 26 91 3 20 5 Exelon $462 $332 $339 $40 $291 $83 (a)Exelon’s and Generation’s pension contributions include $36 million and $43 million related to the legacy CENG plans that was funded by CENG as provided in an EmployeeMatters Agreement (EMA) between Exelon and CENG for the years ended December 31, 2015 and 2014, respectively.(b)Includes $5 million, $9 million, and $72 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2015, 2014, and 2013, 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 372 (a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status(which triggers higher minimum contribution requirements and participant notification). Additionally, the projected contribution reflects a fundingstrategy of contributing the greater of $250 million until the qualified plans are fully funded on an ABO basis, and the minimum amounts underERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pensioncontributions. Exelon plans to contribute $250 million to its qualified pension plans in 2016, of which Generation, ComEd, PECO, and BGE will contribute$134 million, $30 million, $28 million, and $31 million, respectively. Exelon’s and Generation’s expected qualified pension plan contributions aboveinclude $25 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 $21 million in 2016, of which Generation, ComEd, PECO, and BGE will make payments of $9 million, $2 million, $1 millionand $1 million, respectively. 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 2016, 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 $35 million in 2016, of which Generation, ComEd, PECO, and BGE expect to contribute $13million, $3 million, $1 million, and $18 million, respectively. Estimated Future Benefit Payments Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2015 were: PensionBenefits OtherPostretirementBenefits 2016 $1,153 $217 2017 997 223 2018 1,009 228 2019 1,036 235 2020 1,071 244 2021 through 2025 5,923 1,341 Total estimated future benefit payments through 2025 $11,189 $2,488 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 373Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based onthe number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. The obligation for Generation, ComEd andPECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon hasallocated the components of pension and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors,including the measures of active employee participation in each participating unit. Pension and other postretirement benefit contributions wereallocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. Beginning in2015, Exelon began allocating costs related to its legacy Exelon pension and other postretirement benefit plans to its subsidiaries based on bothactive and retired employee participation and contributions are allocated based on accounting cost. The impact of this allocation methodologychange is not material to any Registrant. For legacy CEG and legacy CENG plans, components of pension and other postretirement benefit costsand contributions have been, and will continue to be, allocated to the subsidiaries based on employee participation (both active and retired). The amounts below were included in capital expenditures and Operating and maintenance expense for the years ended December 31, 2015,2014 and 2013, respectively, for Generation’s, ComEd’s, PECO’s, BSC’s and BGE’s allocated portion of the pension and other postretirementbenefit plan costs. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges: For the Year Ended December 31, Generation ComEd PECO BSC BGE Exelon 2015 $269 $206 $39 $57 $66 637 2014 250 162 36 46 67 561 2013 347 309 43 71 55 825 (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. 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 6.71% to estimate its 2016 pension and other postretirement benefit costs, respectively. 374 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 pension and other postretirement benefit plan target asset allocations at December 31, 2015 and 2014 asset allocations were asfollows: Pension Plans Percentage of Plan Assetsat December 31, Asset Category Target Allocation 2015 2014 Equity securities 32% 35% 33% Fixed income securities 37% 34 37 Alternative investments 31% 31 30 Total 100% 100% Other Postretirement Benefit Plans Percentage of Plan Assetsat December 31, Asset Category Target Allocation 2015 2014 Equity securities 39% 43% 42% Fixed income securities 26% 27 34 Alternative investments 35% 30 24 Total 100% 100% (a)Alternative investments include private equity, hedge funds, real estate, and private credit. 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, 2015. 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, 2015, there were nosignificant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets. 375 (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 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, 2015 and 2014: At December 31, 2015 Level 1 Level 2 Level 3 Total Pension plan assets Cash equivalents $210 $— $— $210 Equities 3,571 1,462 2 5,035 Fixed income: U.S. Treasury and agencies 1,001 79 — 1,080 State and municipal debt — 61 — 61 Corporate debt — 2,901 165 3,066 Other — 395 203 598 Fixed income subtotal 1,001 3,436 368 4,805 Private equity — — 924 924 Hedge funds — 1,129 795 1,924 Real estate — — 725 725 Private credit — — 699 699 Pension plan assets subtotal 4,782 6,027 3,513 14,322 At December 31, 2015 Level 1 Level 2 Level 3 Total Other postretirement benefit plan assets Cash equivalents 15 — — 15 Equities 510 482 — 992 Fixed income: U.S. Treasury and agencies 11 53 — 64 State and municipal debt — 131 — 131 Corporate debt — 44 — 44 Other 155 205 — 360 Fixed income subtotal 166 433 — 599 Hedge funds — 312 139 451 Real estate — — 131 131 Private credit — — 103 103 Other postretirement benefit plan assets subtotal 691 1,227 373 2,291 Total pension and other postretirement benefit plan assets $5,473 $7,254 $3,886 $16,613 376 (a)(b) (b) (a) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Pension plan assets Cash equivalents $1 $— $— $1 Equities 3,261 1,449 2 4,712 Fixed income: U.S. Treasury and agencies 1,051 88 — 1,139 State and municipal debt — 80 — 80 Corporate debt — 3,125 120 3,245 Other — 930 152 1,082 Fixed income subtotal 1,051 4,223 272 5,546 Private equity — — 900 900 Hedge funds — 1,355 785 2,140 Real estate 243 — 685 928 Private credit — — 607 607 Pension plan assets subtotal 4,556 7,027 3,251 14,834 At December 31, 2014 Level 1 Level 2 Level 3 Total Other postretirement benefit plan assets Cash equivalents 11 — — 11 Equities 480 525 — 1,005 Fixed income: U.S. Treasury and agencies 15 59 — 74 State and municipal debt — 197 — 197 Corporate debt — 42 — 42 Other 253 272 — 525 Fixed income subtotal 268 570 — 838 Hedge funds — 339 — 339 Real estate 8 — 116 124 Private credit — — 110 110 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 (a)See Note 12—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.(b)Includes derivative instruments of $5 million and $(3) million, which have a total notional amount of $1,774 million and $1,491 million at December 31, 2015 and 2014,respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not representthe amount of the company’s exposure to credit or market loss.(c)Excludes net assets of $27 million and $42 million at December 31, 2015 and 2014, 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. 377 (a) (b) (b) (a) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014: Hedgefunds Privateequity Realestate Fixedincome Equities PrivateCredit Total Pension Assets Balance as of January 1, 2015 $785 $900 $685 $272 $2 $607 $3,251 Actual return on plan assets: Relating to assets still held at the reporting date (39) 60 76 (14) — (19) 64 Relating to assets sold during the period 4 — 9 — — — 13 Purchases, sales and settlements: Purchases 104 186 116 125 — 200 731 Sales (57) — (54) (7) — (5) (123) Settlements (2) (222) (107) (8) — (84) (423) Balance as of December 31, 2015 $795 $924 $725 $368 $2 $699 $3,513 Other Postretirement Benefits Balance as of January 1, 2015 $— $— $116 $— $— $110 $226 Actual return on plan assets: Relating to assets still held at the reporting date 1 — 15 — — (7) 9 Purchases, sales and settlements: Purchases 138 — 62 — — — 200 Settlements — — (62) — — — (62) Balance as of December 31, 2015 $139 $— $131 $— $— $103 $373 Hedgefunds Privateequity Realestate Fixedincome Equities Privatecredit Total Pension Assets Balance as of January 1, 2014 $706 $806 $544 $41 $2 $371 $2,470 Actual return on plan assets: Relating to assets still held at the reporting date 59 112 81 7 — 20 279 Relating to assets sold during the period 2 — — — — 1 3 Purchases, sales and settlements: Purchases 74 169 112 227 — 265 847 Sales (25) — (19) (3) — (13) (60) Settlements (1) (203) (60) — — (37) (301) Transfers into (out of) Level 3 (30) 16 27 — — — 13 Balance as of December 31, 2014 $785 $900 $685 $272 $2 $607 $3,251 Other Postretirement Benefits Balance as of January 1, 2014 $— $2 $109 $— $— $4 $115 Actual return on plan assets: Relating to assets still held at the reporting date — — 13 — — 1 14 Purchases, sales and settlements: Purchases — 1 1 — — 109 111 Sales — (2) (7) — — (4) (13) Settlements — (1) — — — — (1) Balance as of December 31, 2014 $— $— $116 $— $— $110 $226 378 (a) (a) (a) (b)(c) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)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, 2015 and January 1, 2014, 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, restrictions for certain investments no longer applied, therefore allowing redemption within areasonable 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 in 2014. There were no transfers between Level 1 and Level 2 during the twelve months ended December 31, 2015 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 market exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including real estateinvestment trusts, rights and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume tradingrequirements imposed by these exchanges. Equity securities are valued based on quoted prices in active markets and are categorized as Level 1.Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significantunobservable 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. With respect to individually held fixed income securities, 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.Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving suchprices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other 379Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid andtransparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certainsignificant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments,are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted forobservable differences and are categorized as Level 2 Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investmentcompanies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investmentstrategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based onquoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are notpublicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of theunderlying securities. These funds have been categorized as Level 2. Certain fixed income commingled funds are valued using the NAV per fundshare, which is based on the valuation of the underlying investments and include significant unobservable inputs. These funds have beencategorized 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. 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 funds are funds with a direct investment in pools 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. Private credit. Private credit investments primarily consist of limited partnerships that invest in private debt strategies. These investmentsare generally less liquid assets with an underlying term of 3 380Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator andinclude unobservable inputs such as cost, operating results, and discounted cash flows. Since the valuation inputs are not highly observable,private credit investments have been categorized as Level 3. 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, 2015, 2014 and 2013: For the Year Ended December 31, Exelon Generation ComEd PECO BGE BSC 2015 $148 $80 $32 $11 $14 $11 2014 103 51 26 8 8 10 2013 85 40 22 8 8 7 (a)Includes $9 million and $5 million related to CENG for the year ended December 31, 2015, and for the period from April 1, 2014 to December 31, 2014, respectively.(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. 18. Contingently Redeemable Noncontrolling Interest (Exelon, Generation) In November 2015, 2015 ESA Investco, LLC, a wholly owned subsidiary of Generation, entered into an arrangement to sell a portion of itsequity to a tax equity investor. Pursuant to the operating agreement, in certain situations the equity contributions made by the noncontrollinginterest holder could be contingently redeemable. These situations are outside of the control of Generation and the noncontrolling interest holderresulting in a portion of the noncontrolling interest being considered contingently redeemable and thus presented in mezzanine equity in theconsolidated balance sheet. The following table summarizes the changes in the contingently redeemable noncontrolling interest for the year ended December 31, 2015: Year Ended December 31,2015 Beginning Balance $— Cash received from noncontrolling interest 32 Release of contingency (4) Ending Balance $28 381 (a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 19. Shareholder’s Equity (Exelon, ComEd, PECO and BGE) The following table presents common stock authorized and outstanding as of December 31, 2015 and 2014: December 31, 2015 2014 Par Value SharesAuthorized Shares Outstanding Common Stock Exelon no par value 2,000,000,000 919,924,742 859,833,343 ComEd $12.50 250,000,000 127,016,973 127,016,947 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 73,434 and 73,533 warrants outstanding to purchase ComEd common stock at December 31, 2015 and 2014, 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, 2015 and 2014, 24,478 and 24,511 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 with two counterparties. In July 2015, Exelon settled the forward saleagreement by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which wascalculated based on a forward price of $32.48 per share as specified in the forward sale agreements. Use of net proceeds will be to fund thepending merger with PHI and related costs and expenses, and for general corporate purposes. The forward sale agreements are classified asequity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forwardsale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of diluted EPS usingthe 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 14—Debt and Credit Agreements for further information on the equity units. Share Repurchases Share Repurchase Programs. There currently is no Exelon Board of Director authority to repurchase shares. Any previous sharesrepurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Under the previousshare repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2015. During2015, 2014 and 2013, Exelon had no common stock repurchases. Preferred and Preference Securities of Subsidiaries At December 31, 2015 and 2014, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which wereoutstanding. 382Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014, 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. At December 31, 2015 and 2014, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized of which1,900,000 are outstanding as set forth in the table 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 that i) with regards to either dividends or distribution of assets,would create or authorize any shares of stock ranking prior to or on a parity with the preference stock or ii) substantially adversely affectthe contract rights, as expressly set forth in BGE’s charter, of the preference stock. Each such amendment would require the affirmativevote of two-thirds of all the shares of preference stock outstanding; and • Whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock 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 2015 2014 2015 2014 Shares Outstanding DollarAmount 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 100.00 600,000 600,000 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. 20. Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) 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, 2015, there were approximately 16 million shares authorized for issuance under the LTIP. For the years endedDecember 31, 2015, 2014 and 2013, 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 383(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015, 2014 and 2013: Year EndedDecember 31, Components of Stock-Based Compensation Expense 2015 2014 2013 Performance share awards $41 $59 $48 Restricted stock units 71 61 61 Stock options 1 2 3 Other stock-based awards 6 5 6 Total stock-based compensation expense included in operating and maintenance expense 119 127 118 Income tax benefit (46) (47) (44) Total after-tax stock-based compensation expense $73 $80 $74 The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2015, 2014 and 2013: Year EndedDecember 31, Subsidiaries 2015 2014 2013 Generation $64 $52 $48 ComEd 6 7 9 PECO 3 3 5 BGE 3 5 6 BSC 43 60 50 Total $119 $127 $118 (a)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, 2015, 2014 and 2013. 384 (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 following table presents information regarding Exelon’s tax benefits for the years ended December 31, 2015,2014 and 2013: Year EndedDecember 31, 2015 2014 2013 Realized tax benefit when exercised/distributed: Restricted stock units $30 $17 $11 Performance share awards 18 11 11 Stock deferral plan — — 1 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, 2014 or 2015. For all stock options granted through 2012, the exercise price of the stockoptions is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally fouryears. All stock options expire ten years from the date of grant. The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The 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 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 385Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected liferepresents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that thesimplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimateof expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis andadjusted as necessary. The following table presents information with respect to stock option activity for the year ended December 31, 2015: Shares WeightedAverageExercisePrice(pershare) WeightedAverageRemainingContractualLife(years) AggregateIntrinsicValue Balance of shares outstanding at December 31, 2014 18,830,967 $46.85 Options exercised (7,133) 21.25 Options forfeited (5,250) 39.81 Options expired (3,245,827) 47.75 Balance of shares outstanding at December 31, 2015 15,572,757 $46.68 3.85 $9 Exercisable at December 31, 2015 15,490,507 $46.72 3.84 $9 (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, 2015, 2014 and2013: Year EndedDecember 31, 2015 2014 2013 Intrinsic value $— $3 $4 Cash received for exercise price — 7 19 (a)The difference between the market value on the date of exercise and the option exercise price. The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2015: Shares Weighted AverageExercise Price(per share) Nonvested at December 31, 2014 432,035 $39.91 Vested (344,535) 39.93 Forfeited (5,250) 39.81 Nonvested at December 31, 2015 82,250 $39.81 (a)Excludes 279,000 and 746,140 of stock options issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested. At December 31, 2015, $0.1 million of total unrecognized compensation costs related to nonvested stock options are expected to berecognized over the remaining weighted-average period of less than a year. 386(a) (a)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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, 2015: Shares Weighted AverageGrant Date FairValue (per share) Nonvested at December 31, 2014 3,758,218 $31.27 Granted 2,132,856 36.55 Vested (1,597,255) 32.88 Forfeited (76,232) 33.06 Undistributed vested awards (654,333) 35.35 Nonvested at December 31, 2015 3,563,254 $32.92 (a)Excludes 1,097,630 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.(b)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2015. The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2015, 2014 and2013 was $36.55, $28.71 and $31.06, respectively. At December 31, 2015 and 2014, Exelon had obligations related to outstanding restricted stockunits not yet settled of $97 million and $85 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets.For the years ended December 31, 2015, 2014 and 2013, Exelon settled restricted stock units with fair value totaling $75 million, $43 million and$28 million, respectively. At December 31, 2015, $56 million of total unrecognized compensation costs related to nonvested restricted stock unitsare expected to be recognized over the remaining weighted-average period of 2 years. Performance Share Awards Performance share awards are granted under the LTIP. The 2015 and 2014 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. 387(a) (b)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 is recognized ratably over the vesting period, which is the year of grant. The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2015: Shares Weighted AverageGrant Date FairValue (per share) Nonvested at December 31, 2014 2,696,097 $30.62 Granted 1,556,273 35.88 Change in performance (118,398) 35.88 Vested (704,141) 32.80 Forfeited (52,167) 32.25 Undistributed vested awards (820,505) 33.95 Nonvested at December 31, 2015 2,557,159 $31.88 (a)Excludes 1,817,883 and 1,535,791 of performance share awards issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fullyvested.(b)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2015. The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2015,2014 and 2013 was $35.88, $28.75, and $31.55, respectively. During the years ended December 31, 2015, 2014 and 2013, Exelon settledperformance shares with a fair value totaling $46 million, $27 million and $26 million, respectively, of which $29 million, $13 million and $12 millionwas paid in cash, respectively. As of December 31, 2015, $27 million of total unrecognized compensation costs related to nonvested performanceshares are expected to be recognized over the remaining weighted-average period of 1.4 years. The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled: December 31, 2015 2014 Current liabilities $28 $28 Deferred credits and other liabilities 32 36 Common stock 35 33 Total $95 $97 (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. 388(a)(b)(a) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Earnings Per Share (Exelon) 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, 2015 2014 2013 Net income attributable to common shareholders $2,269 $1,623 $1,719 Weighted average common shares outstanding—basic 890 860 856 Assumed exercise and/or distributions of stock-based awards 3 4 4 Weighted average common shares outstanding—diluted 893 864 860 The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect wasapproximately 16 million in 2015, 17 million in 2014, and 20 million in 2013. 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 3 million for the year ended December 2015 and less than1 million for the year ended December 31, 2014. Additionally, there were no forward units related to the PHI merger not included in the calculationof diluted common shares outstanding due to their antidilutive effect for the years ended December 31, 2015 and 2014. Refer to Note 19—Shareholder’s Equity for further information regarding the equity units and equity forward units. Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as ofDecember 31, 2015. In 2008, Exelon management decided to defer indefinitely any share repurchases. 389Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 22. 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, 2015 and 2014: For the Year Ended December 31, 2015 Gains and(Losses) onCash FlowHedges UnrealizedGains and(Losses) onMarketableSecurities Pension andNon-Pension PostretirementBenefit Plan Items ForeignCurrencyItems AOCI ofEquityInvestments Total Exelon Beginning balance $(28) $3 $(2,640) $(19) $— $(2,684) OCI before reclassifications (12) — (100) (21) (3) (136) Amounts reclassified from AOCI 21 — 175 — — 196 Net current-period OCI 9 — 75 (21) (3) 60 Ending balance $(19) $3 $(2,565) $(40) $(3) $(2,624) Generation Beginning balance $(18) $1 $— $(19) $— $(36) OCI before reclassifications (8) — — (21) (3) (32) Amounts reclassified from AOCI 5 — — — — 5 Net current-period OCI (3) — — (21) (3) (27) Ending balance $(21) $1 $— $(40) $(3) $(63) PECO Beginning balance $— $1 $— $— $— $1 OCI before reclassifications — — — — — — Amounts reclassified from AOCI — — — — — — Net current-period OCI — — — — — — Ending balance $— $1 $— $— $— $1 390 (a) (b) (a) (b) (a) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Gains and(Losses) onCash FlowHedges UnrealizedGains and (Losses) onMarketable Securities Pension andNon-Pension PostretirementBenefit Plan items ForeignCurrencyItems AOCI ofEquity Investments 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 (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. 391 (a)(b) (a)(b) (a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and2014. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years endedDecember 31, 2015 and 2014: For the Year Ended December 31, 2015Details about AOCI components Items reclassified out of AOCI Affected line item in the Statementsof Operations and Comprehensive Income Exelon Generation Gains and (losses) on cash flow hedges Terminated interest rate swaps $(26) $— Other, netEnergy related hedges 2 2 Operating revenuesOther cash flow hedges (11) (11) Interest expenseTotal before tax (35) (9) Tax benefit 14 4 Net of tax $(21) $(5) Comprehensive incomeAmortization of pension and otherpostretirement benefit plan items Prior service costs $74 $— Actuarial losses (361) — Total before tax (287) — Tax benefit 112 — Net of tax $(175) $— Total Reclassifications $(196) $(5) Comprehensive income 392(a) (b) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2014Details about AOCI components Items reclassified out of AOCI Affected line item in the Statementsof Operations and Comprehensive Income Exelon Generation Gains and (losses) on cash flow hedges Energy related hedges $195 $195 Operating revenuesTotal before tax 195 195 Tax expense (78) (78) Net of tax $117 $117 Comprehensive incomeGains and (losses) on available for salesecurities Other available securities for sale $(2) $— Other Income and DeductionsTotal before tax (2) — Net of tax $(2) $— Comprehensive incomeAmortization of pension and otherpostretirement benefit plan items Prior service costs $46 $— Actuarial losses (239) — Total before tax (193) — Tax benefit 75 — Net of tax $(118) $— Comprehensive incomeEquity investments Sale of equity method investment $5 $5 Equity in losses of unconsolidated affiliatesReversal of CENG equity method AOCI 193 193 Gain on Consolidation of CENGTotal before tax 198 198 Tax expense (79) (79) Net of tax $119 $119 Total Reclassifications $116 $236 Comprehensive income (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 17—Retirement Benefits for additionaldetails).(c)Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. 393(a) (b) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014: For the Years EndedDecember 31, 2015 2014 2013 Exelon Pension and non-pension postretirement benefit plans: Prior service benefit reclassified to periodic benefit cost $30 $19 $— Actuarial loss reclassified to periodic cost (140) (93) (133) Pension and non-pension postretirement benefit plan valuation adjustment 62 317 (430) Change in unrealized (gain) loss on cash flow hedges (6) 96 166 Change in unrealized (gain) loss on equity investments 1 73 (71) Total $(53) $412 $(468) Generation Change in unrealized loss on cash flow hedges $2 $84 $262 Change in unrealized (gain) loss on equity investments 1 73 (72) Total $3 $157 $190 23. Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) Commitments Constellation Merger Commitments 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 direct investment estimate includes $95 million to $120 million relating to the construction ofa headquarters building in Baltimore for Generation’s competitive energy businesses. The direct investment commitment also includes $500 million to $600 million relating to Exelon and Generation’s development or assistancein the development of 275—300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years. Exelon andGeneration have incurred $393 million towards satisfying the commitment for new generation development in the state of Maryland, withapproximately 220 MW of the new generation commencing with commercial operations to date. The MDPSC order contemplates various optionsfor complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliancepayments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damagespayments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and,therefore, will be primarily capital in nature and recognized as incurred. However, during the third quarter of 2014, the conditions associated withone of the generation development commitments changed such that Exelon and Generation now believe that the most likely outcome will involvemaking subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon andGeneration recorded a pre-tax $44 million loss contingency related to this generation development commitment which is included in Operating andmaintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and 394Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Comprehensive Income for the year ended December 31, 2014. While this $44 million loss contingency represents Generation’s best estimate ofthe future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of upto a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructedgenerating plant. Equity Investment Commitments As part of Generation’s recent investments in technology development, Generation enters into equity purchase agreements that includecommitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associatedcompanies. The commitment includes approximately $20 million of in-kind services and 100% of 2015 ESA Investco, LLC’s equity commitmentsince 2015 ESA Investco, LLC is consolidated by Generation (see Note 2—Variable Interest Entities for additional details). As of December 31,2015, Generation’s estimated commitment relating to its equity purchase agreements, including in-kind services contributions, is anticipated to beas follows: Total 2016 $299 2017 21 2018 7 2019 — Total $327 (a)The noncontrolling interest holder of 2015 ESA Investco, LLC will contribute up to $172 million in support of a portion of this equity commitment. Commercial Commitments Exelon’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were asfollows: Expiration within Total 2016 2017 2018 2019 2020 2021and beyond Letters of credit (non-debt) $1,583 $1,565 $5 $— $— $13 $— Surety bonds 809 733 49 3 2 16 6 Financing trust guarantees 628 — — — — — 628 Energy marketing contract guarantees 3,126 3,126 — — — — — Nuclear insurance premiums 3,060 — — — — — 3,060 Total commercial commitments $9,206 $5,424 $54 $3 $2 $29 $3,694 (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)Includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust PreferredSecurities of BGE Capital Trust II.(d)Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3.1 billion of guaranteesissued by Exelon and Generation on behalf of its Constellation businesses to allow it the flexibility needed to conduct business with counterparties without having to post otherforms of 395(a) (a) (b) (c) (d) (e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon’s estimated net exposure forobligations under commercial transactions covered by these guarantees is approximately $0.5 billion at December 31, 2015, which represents the total amount Exelon could berequired to fund based on December 31, 2015 market prices.(e)Nuclear insurance premiums—Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at 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. Generation’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were asfollows: Expiration within Total 2016 2017 2018 2019 2020 2021and beyond Letters of credit (non-debt) $1,503 $1,485 $5 $— $— $13 $— Surety bonds 737 692 45 — — — — Energy marketing contract guarantees 1,532 1,532 — — — — — Nuclear insurance premiums 3,060 — — — — — 3,060 Total commercial commitments $6,832 $3,709 $50 $— $— $13 $3,060 (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)Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.5 billion of guaranteesissued by Generation on behalf of its Constellation businesses to allow it the flexibility needed to conduct business with counterparties without having to post other forms ofcollateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimated net exposure forobligations under commercial transactions covered by these guarantees is approximately $0.3 billion at December 31, 2015, which represents the total amount Generation couldbe required to fund based on December 31, 2015 market prices.(c)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, 2015, representing commitments potentially triggered by future events, were asfollows: Expiration within Total 2016 2017 2018 2019 2020 2021and beyond Letters of credit (non-debt) $16 $16 $— $— $— $— $— Surety bonds 8 6 — 2 — — — Financing trust guarantees 200 — — — — — 200 Total commercial commitments $224 $22 $— $2 $— $— $200 (a)Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.(b)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.(c)Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd. 396 (a) (b) (c) (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015, representing commitments potentially triggered by future events, were asfollows: Expiration within Total 2016 2017 2018 2019 2020 2021and beyond Letters of credit (non-debt) $22 $22 $— $— $— $— $— Surety bonds 9 9 — — — — — Financing trust guarantees 178 — — — — — 178 Total commercial commitments $209 $31 $— $— $— $— $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, 2015, representing commitments potentially triggered by future events, were asfollows: Expiration within Total 2016 2017 2018 2019 2020 2021and beyond Letters of credit (non-debt) $2 $2 $— $— $— $— $— Surety bonds 10 10 — — — — — Financing trust guarantees 250 — — — — — 250 Total commercial commitments $262 $12 $— $— $— $— $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 bonds—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. Leases Minimum future operating lease payments, including lease payments for contracted generation, vehicles, real estate, computers, rail cars,operating equipment and office equipment, as of December 31, 2015 were: Exelon Generation ComEd PECO BGE 2016 $133 $86 $14 $3 $12 2017 109 69 9 3 10 2018 86 57 5 2 9 2019 74 45 5 2 8 2020 70 44 3 2 7 Remaining years 702 655 1 — 19 Total minimum future lease payments $1,174 $956 $37 $12 $65 (a)Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.(b)The Generation column above includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective duringthe second quarter of 2015. Generation’s total commitments under the 397 (a) (b) (c) (a) (b) (c)(a) (a)(b)(c)(c)(c)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) lease agreement are $4 million, $10 million, $11 million, $13 million, $14 million, and $271 million related to years 2016, 2017, 2018, 2019, 2020 and thereafter, respectively.(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 2016—2020, was $2 million, $3 million, and $1 million respectively.(d)Includes all future lease payments on a 99 year real estate lease that expires in 2106. The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2015, 2014 and 2013: For the Year Ended December 31, Exelon Generation ComEd PECO BGE 2015 $922 $851 $12 $9 $32 2014 865 806 15 14 12 2013 806 744 15 21 11 (a)Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments tableabove. Payments made under Generation’s contracted generation lease agreements totaled $798 million, $755 million and $694 million during 2015, 2014 and 2013,respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions. For information regarding capital lease obligations, see Note 14—Debt and Credit Agreements. 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 31,2015, the current liability limit per incident is $13.5 billion and is subject to change to account for the effects of inflation and changes in the numberof licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effectiveSeptember 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liabilityinsurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arisein the event of an incident. As of December 31, 2015, the amount of nuclear energy liability insurance purchased is $375 million for each operatingsite. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan forpower reactors (currently 103 reactors) resulting in an additional $13.1 billion in funds available for public liability claims. Participation in thissecondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident thatexceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for eachnuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incidentper year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG’s related liability. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the$13.5 billion limit for a single incident. 398(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreedto indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act)in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG. Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates 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. Generation’s portion of the distributiondeclared by NEIL is estimated to be $20.7 million for 2015, and was $18.3 million for 2014 and $18.5 million for 2013. 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, 2015, the current maximum aggregate annual retrospective premium obligationfor Generation is approximately $365 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. 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 399Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with theNWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost ofSNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNFdisposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal feeremained in effect through May 15, 2014, after which time the fee was set to zero. As a result, for the year ended December 31, 2015, Generationdid not incur any expense in SNF disposal fees. For the year ended December 31, 2014 and 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 ConsolidatedStatements of Operations and Comprehensive Income, including Exelon’s share of Salem and net of co-owner reimbursements (not including suchfees incurred by CENG). Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNFdisposal fees. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required theDOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed tomeet that deadline and its performance has been, and is expected to be, delayed significantly. The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca 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. 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. 400Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 $945 $804 (a)Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.(b)Includes $53 million and $49 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, 2015, and 2014, 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, 2015 December 31, 2014 DOE receivable—current $76 $82 DOE receivable—noncurrent 14 7 Amounts owed to co-owners (5) (5) (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, 2015, 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, 2015,was 0.112%. 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 12—Fair Value of Financial Assets and Liabilities for additionalinformation. 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. 401(a)(b)(a)(b)(a)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 have been remediated and approved by the Illinois EPA or the U.S. EPA and 25 that arecurrently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites tocontinue through at least 2020. • 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. • 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. An investigation of an additional gas purification site was completed duringthe first quarter of 2015 at the direction of the MDE. For more information, see the discussion of the Riverside site below. 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. See Note 3—Regulatory Matters for additionalinformation regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for theremediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE hashistorically received recovery of actual clean-up costs in distribution rates. ComEd, PECO and BGE have recorded regulatory assets for therecovery of these costs. As of December 31, 2015 and 2014, the Registrants had 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, 2015 Total environmentalinvestigationand remediation reserve Portion of total related to MGPinvestigation and remediation Exelon $369 $301 Generation 63 — ComEd 266 264 PECO 37 35 BGE 3 2 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 — (a)For BGE, includes reserve for Riverside, a gas purification site. See discussion below for additional information. 402(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 using all available information at the time of each study, including probabilistic and deterministicmodeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior tocompletion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency. During the third quarter of 2015, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. ForComEd, the results of the study resulted in a $50 million increase to ComEd’s environmental liabilities and related regulatory assets. The increaseat ComEd was primarily driven by refined assumptions and scopes based on further experience and analysis, including one site where a newoption is being considered for a facility under which contamination exists and certain sites where another PRP leads the remediation efforts andComEd shares responsibility. For PECO, the results of the study resulted in a $1 million decrease to PECO’s environmental liabilities and relatedregulatory assets. 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, 2015 and2014, Generation’s remaining groundwater contamination reserve was $12 million and $13 million respectively. Air Quality Notices and Finding of Violations and Midwest Generation Bankruptcy. In December 1999, ComEd sold several generating stations toMidwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, MidwestGeneration and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of thestations, including responsibility for compliance by the stations with environmental laws before their purchase by Midwest Generation. MidwestGeneration and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities andexpenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by MidwestGeneration and EME under the terms of the agreement governing the sale. In connection with Exelon’s 2001 corporate restructuring, Generationassumed ComEd’s rights and obligations with respect to its former generation business, including its rights and obligations under the saleagreement with Midwest Generation and EME. 403Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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. A settlement was reached inJanuary 2015, to resolve the claims related to the coal rail car lease for approximately $14 million and Exelon recorded a gain upon receipt of thefunds, within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statement of Operations and ComprehensiveIncome. No further action is expected related to the rail car lease. 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. Generation increased its reserve for asbestos-related bodily injury claims pertaining to Midwest Generations’ share of liability as a result ofthe rejection of the asbestos cost sharing agreement in the bankruptcy proceedings. Exelon and Generation may be entitled to damagesassociated with the rejection of the agreement and a claim has been filed by Exelon for such damages. These amounts are considered to becontingent gains and would not be recognized until realized. As a prior owner of the generating stations, ComEd (and Generation, through its agreement in Exelon’s 2001 corporate restructuring toassume ComEd’s rights and obligations associated with its former generation business) could face liability (along with any other potentiallyresponsible parties) for environmental conditions at the stations requiring remediation, with the determination of the allocation among the partiessubject to many uncertain factors. ComEd and Generation are unable to predict whether and to what extent they may ultimately be heldresponsible for remediation and other costs relating to the generating stations and as a result no liability has been recorded as of December 31,2015. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverseimpact on their future results of operations and cash flows. 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 404Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) additional landfill cover. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for aremediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted thefinal supplemental feasibility study to the U.S. EPA for review. Since, June 2012, the U.S. EPA has requested that the PRPs perform a series ofadditional analyses and groundwater and soil sampling as part of the supplemental feasibility study, that are now scheduled to be completed inmid-2016 to enable the EPA to propose a remedy for public comment by the end of 2016. Thereafter the U.S. EPA will select a final remedy andenter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive thanthe previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require a completeexcavation remedy is remote. The U.S. EPA is also reviewing a partial excavation remedy; however, until the current sampling is concluded thereis no basis to determine the likelihood and estimate of a partial excavation remedy. The current estimated cost of the landfill cover remediation forthe site is approximately $60 million, which will be allocated among all PRPs. Recent investigation has identified a number of other parties whomay be PRPs and could be liable to contribute to the final remedy. Further investigation is underway. Generation has accrued what it believes tobe an adequate amount to cover its anticipated share of such liability. During December 2015, the U.S. EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent anddangerous conditions at the landfill. The first involved installation of a non-combustible interim surface cover to protect against surface fires inareas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount tocover its anticipated liability for this interim action. The second action involved EPA’s public statement that it will require the PRPs to construct abarrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materialsare believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and designof a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to whichGeneration may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It isreasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation’s and Exelon’s future resultsof operations and cash flows. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that it will bemaking a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the WestLake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficientinformation to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows. On February 2, 2015, the U.S. Senate passed a bill to transfer remediation authority over the West Lake landfill from the U.S. EPA to theU.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). Such legislation would become final uponpassage in the U.S. House of Representatives and the signature of the President, and be subject to annual funding appropriations in the U.S.Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but could delay the determination of a final remedy and itsimplementation. 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 405Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’sManhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction ofuranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of landareas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the FormerlyUtilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to beapproximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2016 so that settlement discussions couldproceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreementand has established an appropriate accrual for this liability. Commencing in February 2012, 37 lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among thedefendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, and Cotter, which remains a defendant.The suits allege that individuals living in the North St. Louis area developed some form of cancer due to Cotter’s negligent or reckless conduct inprocessing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability,emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. In theevent of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotterdescribed above. The court has dismissed the lawsuits filed by 30 of the plaintiffs. Pre-trial motions and discovery are proceeding in the remainingcases and a proposed pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannotestimate a range of loss, if any. 68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National 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), a wholly-owned subsidiaryof Generation. In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) toaddress any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in2010 and is currently 406Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to beapproximately $9 million, which has been fully reserved as of December 31, 2015. 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 PRPs signed an Administrative Settlement Agreement and Order onConsent with the U.S. EPA which requires the PRPs to conduct a remedial investigation and feasibility study at the site to determine what, if any,are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPAhas not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range ofBGE’s reasonably possible loss, if any, cannot be determined. Riverside. In 2013, the Maryland Department of the Environment (MDE), at the request of U.S. EPA, conducted a site inspection and limitedenvironmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels withdifferent current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants.The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014,the MDE requested that BGE conduct an investigation of three specific areas of the site, and a site-wide investigation of soils, sediment,groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report wasprovided to MDE on June 2, 2015. On November 3, 2015, MDE provided BGE with its comments and recommendations on the report which requireBGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-sitesediment and soil sampling. MDE did not request any interim remediation at this time. Upon completion of the investigation the MDE will determineif the site requires further action and/or remediation. Based upon the investigation to date, BGE has established what it believes is an appropriatereserve. As the investigation and potential remediation proceed, it is possible that additional reserves could be established, in amounts that couldbe material to BGE. 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, 2015 and 2014, Generation had reserved approximately $95 million and $100 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2015, approximately $21 million of this amount related to 228 open claims presented toGeneration, while the remaining $74 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. 407Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 preclude suchemployee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Courtprecluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workerscompensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Sincethe Pennsylvania Supreme Court’s ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-relatedpersonal injury claims brought by former PECO employees, all of which have been reserved against on a claim by claim basis. Those additionalclaims are taken into account in projecting estimated future asbestos-related bodily injury claims. On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois’ Workers’ Compensation Act and the Workers’Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court’s ruling reversed previous rulings by theIllinois Court of Appeals, which initially ruled that the Illinois Worker’s Compensation law should not apply in cases where the diagnosis of anasbestos related disease occurred after the 25-year maximum time period for filing a Worker’s Compensation claim. As a result of this ruling,Exelon, Generation, and ComEd have not recorded an increase to the asbestos-related bodily injury liability as of December 31, 2015. There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims inexcess of the amount accrued and the increases could have a material adverse effect on Exelon’s, Generation’s and PECO’s future results ofoperations and cash flows. BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos.The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestoshazard. In addition to BGE and Generation, numerous other parties are defendants in these cases. Approximately 454 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; 408Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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. 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. As of December 31, 2015 and 2014, ComEd did not have anymaterial liabilities recorded for these storm events. 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 alleged thatComEd violated the Telephone Consumer Protection Act (TCPA) by sending text messages to customers without first obtaining their consent toreceive such messages. The complaint sought certification of a class along with statutory damages, attorneys’ fees, and an order prohibitingComEd from sending additional text messages. ComEd and the plaintiff agreed in principle to settle the suit for $5 million, with payments to theclass commencing in the fourth quarter 2015. 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 409Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financingsarranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its rightto extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of thepayment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under whichthe 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 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 preferredtrust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE was prohibited from paying a dividend on its commonshares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’sequity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating israted by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare adividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stockdividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and anydeferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE’s preference stock have not been paid. Baltimore City Franchise Taxes (BGE) The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years withoutthe proper franchise rights from the City. BGE has reviewed the City’s claim and believes that it lacks merit. BGE has not recorded an accrual forpayment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed infuture periods may be material to BGE’s results of operations and cash flows. General (Exelon, Generation, ComEd, PECO and BGE) The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. 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 410Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including apossible eventual loss. Income Taxes (Exelon, Generation, ComEd, PECO and BGE) See Note 15—Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999sale of fossil generating assets. 24. 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, 2015, 2014 and 2013. For the year ended December 31, 2015 Exelon Generation ComEd PECO BGE Taxes other than income Utility $474 $105 $236 $133 $85 Property 407 250 27 11 119 Payroll 201 118 28 14 16 Other 118 16 5 2 4 Total taxes other than income $1,200 $489 296 $160 $224 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 (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. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ ConsolidatedStatements of Operations and Comprehensive Income. 411 (a) (a) (a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Exelon Generation ComEd PECO BGE Other, Net Decommissioning-related activities: Net realized income on decommissioning trust funds — Regulatory agreement units $232 $232 $— $— $— Non-regulatory agreement units 156 156 — — — Net unrealized losses on decommissioning trust funds— Regulatory agreement units (282) (282) — — — Non-regulatory agreement units (197) (197) — — — Net unrealized gains on pledged assets— Zion Station decommissioning 7 7 — — — Regulatory offset to decommissioning trust fund-related activities 21 21 — — — Total decommissioning-related activities (63) (63) — — — Investment income (loss) 8 3 — (2) 4 Long-term lease income 15 — — — — Interest income related to uncertain income tax positions 1 1 — — — AFUDC—Equity 24 — 5 5 14 Terminated interest rate swaps (26) — — — — PHI merger related debt exchange (22) — — — — Other 17 (1) 16 2 — Other, net $(46) $(60) $21 $5 $18 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 $18 412(a)(b)(c)(d)(e)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 (a)Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning 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 16—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.(d)In January 2015, in connection with Generation’s $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As theoriginal forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As aresult, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income.(e)See Note 14—Debt and Credit Agreements and 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange. 413(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Supplemental Cash Flow Information The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years endedDecember 31, 2015, 2014 and 2013. For the year ended December 31, 2015 Exelon Generation ComEd PECO BGE Depreciation, amortization, accretion and depletion Property, plant and equipment $2,227 $1,007 $635 $240 $289 Regulatory assets 170 — 72 20 77 Amortization of intangible assets, net 54 47 — — — Amortization of energy contract assets and liabilities 22 22 — — — Nuclear fuel 1,116 1,116 — — — ARO accretion 398 397 — — — Total depreciation, amortization, accretion and depletion $3,987 $2,589 $707 $260 $366 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 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 and accretion $3,779 $2,559 $669 $228 $348 (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. 414 (a) (b) (c) (a) (b) (c) (a) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Exelon Generation ComEd PECO BGE Cash paid (refunded) during the year: Interest (net of amount capitalized) $930 $348 $308 $94 $120 Income taxes (net of refunds) 342 476 (265) 64 73 Other non-cash operating activities: Pension and non-pension postretirement benefit costs $637 $269 $206 $39 $65 Loss from equity method investments 7 8 — — — Provision for uncollectible accounts 120 22 53 30 15 Provision for excess and obsolete inventory 10 9 1 — — Stock-based compensation costs 97 — — — — Other decommissioning-related activity (82) (82) — — — Energy-related options 21 21 — — — Amortization of regulatory asset related to debt costs 7 — 5 2 — Amortization of rate stabilization deferral 73 — — — 73 Amortization of debt fair value adjustment (17) (17) — — — Amortization of debt costs 58 15 4 2 2 Discrete impacts from EIMA 144 — 144 — — Lower of cost or market inventory adjustment 23 23 — — — Other 11 — 3 (3) (18) Total other non-cash operating activities $1,109 $268 $416 $70 $137 Non-cash investing and financing activities: Change in PPE related to ARO update $885 $885 $— $— $— Change in capital expenditures not paid 96 82 34 (13) (9) Non-cash financing of capital projects 77 77 — — — Nuclear fuel procurement 57 57 — — — Indemnification of like-kind exchange position — — 7 — — Long-term software licensing agreement 95 — — — — (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 16—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 to the nuclear fuel procurement contract for the purchase of fixed quantities of converted uranium, which was delivered to Generation in 2015. Generation is required tomake payments starting September 28, 2018, with the final payment being due no later than September 30, 2020.(e)See Note 15—Income Taxes for discussion of the like-kind exchange tax position.(f)Relates to a long-term software license agreement entered into on May 30, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See Note14—Debt and Credit Agreements for additional information. 415 (a) (b) (c)(d)(e)(f)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Non-cash investing and financing activities: Change in PPE related to ARO update $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 16—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)Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.(e)See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.(f)Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 20—Stock-Based Compensation Plans for additional information.(g)Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation in 2014. Generation is required to makepayments starting June 30, 2016, with the final payment being due no later than June 30, 2018.(h)See Note 15—Income Taxes for discussion of the like-kind exchange tax position. 416(a)(b)(c)(d)(e)(f)(g)(h)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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 Non-cash investing and financing activities: Change in PPE related to ARO update $(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 16—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 pre-established performance-based formula rate tariff. SeeNote 3—Regulatory Matters.(d)Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.(e)See Note 15—Income Taxes for discussion of the like-kind exchanged tax position. 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. For the year ended December 31, 2015, PECO had no capital expenditures or reimbursements, as theDOE SGIG program was completed during 2014. For the year ended December 31, 2013, Exelon, PECO and BGE have included in the capitalexpenditures line item under investing activities of the cash flow statement capital expenditures of $74 million, $27 million and $47 million, andreimbursements of $95 million, $37 million and $58 million, related to PECO’s and BGE’s DOE SGIG programs. See Note 3—Regulatory Mattersfor additional information regarding the DOE SGIG. 417(a)(b)(c)(d)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) Supplemental Balance Sheet Information The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2015 and 2014. December 31, 2015 Exelon Generation ComEd PECO BGE Investments Equity method investments: Financing trusts $22 $— $6 $8 $8 Bloom 63 63 — — — Net Power 23 23 — — — Other equity method investments 4 3 — — — Total equity method investments 112 89 6 8 8 Other investments: Net investment in leases 358 6 — — — Employee benefit trusts and investments 85 31 — 20 4 Other cost method investments 55 55 — — — Other available for sale investments 29 29 — — — Total investments $639 $210 $6 $28 $12 December 31, 2014 Exelon Generation ComEd PECO BGE Investments Equity method investments: Financing trusts $22 $— $6 $8 $8 Bloom 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 cost method investments 37 37 — — — Other available for sale investments 5 5 — — — Total investments $544 $104 $6 $31 $12 (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)Represents direct financing lease investments. See Note 8—Impairment of Long-Lived Assets for additional information.(c)The Registrants’ investments in these marketable securities are recorded at fair market value. 418 (a)(b) (c) (a)(b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 and 2014. December 31, 2015 Exelon Generation ComEd PECO BGE Accrued expenses Compensation-related accruals $1,014 $547 $183 $66 $57 Taxes accrued 293 186 63 4 23 Interest accrued 915 77 443 35 27 Severance accrued 21 11 3 — 1 Other accrued expenses 133 114 14 4 2 Total accrued expenses $2,376 $935 $706 $109 $110 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 — Total accrued expenses $1,539 $886 $331 $91 $131 (a)Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.(b)Includes $19 million for amounts accrued related to Antelope Valley as of December 31, 2014. 25. 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, which include ComEd, PECO, BGE and Generation’s six power marketing reportable segments,consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other PowerRegions”, which includes activities in the South, West and Canada. ComEd, PECO and BGE each represent a single reportable segment, and assuch, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO and BGE’s CODMs evaluate the performance ofand allocate resources to ComEd, PECO and BGE based on net income and return on equity. The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in differentgeographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provideelectricity through various distribution channels (wholesale and retail). Generation’s hedging strategies and risk metrics are also aligned to thesesame geographic regions. Descriptions of each of Generation’s six reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware,the District of Columbia and parts of Pennsylvania and North Carolina. 419 (a) (a)(b)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, Pennsylvania, Indiana, Ohio, Michigan,Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most ofNorth Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio notcovered 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 Power Regions: • 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 AESO, OIESO and the Canadian portion of MISO. The CODMs for Exelon and Generation evaluate the performance of Generation’s power marketing activities and allocate resources basedon revenue net of purchased power and fuel expense (RNF). Generation believes that RNF is a useful measurement of operational performance.RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than theGAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales toComEd, PECO, and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity,energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tollingagreements. The results of Generation’s other business activities are not regularly reviewed by the CODM and are therefore not classified asoperating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneousbusiness activities that are not significant to Generation’s overall operating revenues or results of operations. Further, Generation’s unrealizedmark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating tocommodity contracts recorded at fair value from mergers and acquisitions are also not included in the regional reportable segment amounts.Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performanceof these reportable segments. 420Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015, 2014, and 2013 is as follows: Generation ComEd PECO BGE Other IntersegmentEliminations Exelon Operating revenues: 2015 Competitive businesses electric revenues $15,944 $— $— $— $— $(744) $15,200 Competitive businesses natural gas revenues 2,433 — — — — — 2,433 Competitive businesses other revenues 758 — — — — (1) 757 Rate-regulated electric revenues — 4,905 2,486 2,490 — (5) 9,876 Rate-regulated natural gas revenues — — 546 645 — (15) 1,176 Shared service and other revenues — — — — 1,372 (1,367) 5 2014 Competitive businesses electric revenues $14,533 $— $— $— $— $(760) $13,773 Competitive businesses natural gas revenues 2,705 — — — — (1) 2,704 Competitive businesses other revenues 155 — — — — (1) 154 Rate-regulated electric revenues — 4,564 2,448 2,460 — (5) 9,467 Rate-regulated natural gas revenues — — 646 705 — (26) 1,325 Shared service and other revenues — — — — 1,285 (1,279) 6 2013 Competitive businesses electric revenues $13,862 $— $— $— $— $(1,366) $12,496 Competitive businesses natural gas revenues 1,721 — — — — — 1,721 Competitive businesses other revenues 47 — — — — (1) 46 Rate-regulated electric revenues — 4,464 2,500 2,405 — (4) 9,365 Rate-regulated natural gas revenues — — 600 660 — (14) 1,246 Shared service and other revenues — — — — 1,241 (1,227) 14 Intersegment revenues: 2015 $745 $4 $2 $14 $1,367 $(2,127) $5 2014 762 4 2 25 1,280 (2,067) 6 2013 1,367 3 1 13 1,237 (2,607) 14 Depreciation and amortization 2015 $1,054 $707 $260 $366 $63 $— $2,450 2014 967 687 236 371 53 — 2,314 2013 856 669 228 348 52 — 2,153 Operating expenses : 2015 $16,872 $3,889 $2,404 $2,578 $1,444 $(2,131) $25,056 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 Equity in earnings (losses) of unconsolidated affiliates 2015 $(8) $— $— $— $1 $— $(7) 2014 (20) — — — — — (20) 2013 10 — — — — — 10 Interest expense, net: 2015 $365 $332 $114 $99 $123 $— $1,033 2014 356 321 113 106 169 — 1,065 2013 357 579 115 122 183 — 1,356 Income (loss) before income taxes: 2015 $1,850 $706 $521 $477 $(219) $(5) $3,330 2014 1,226 676 466 351 (227) (6) 2,486 2013 1,675 401 557 344 (191) (13) 2,773 Income taxes: 2015 $502 $280 $143 $189 $(41) $— $1,073 2014 207 268 114 140 (63) — 666 2013 615 152 162 134 (20) 1 1,044 Net income (loss): 2015 $1,340 $426 $378 $288 $(177) $(5) $2,250 2014 1,019 408 352 211 (164) (6) 1,820 2013 1,060 249 395 210 (171) (14) 1,729 Capital expenditures: 2015 $3,841 $2,398 $601 $719 $65 $— 7,624 2014 3,012 1,689 661 620 95 — 6,077 2013 2,752 1,433 537 587 86 — 5,395 Total assets: 2015 $46,529 $26,532 $10,367 $8,295 $15,389 $(11,728) $95,384 2014 44,951 25,358 9,860 8,056 9,711 (11,520) 86,416 421(a)(b) (c) (d)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Power Regions. For the yearended December 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $224 million and sales to BGE of $502 million in the Mid-Atlantic region,and sales to ComEd of $18 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2014, intersegment revenues for Generationinclude revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, whicheliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales toBGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related tothe ComEd swap, which eliminate upon consolidation.(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.(c)For the years ended December 31, 2015, 2014 and 2013, utility taxes of $105 million, $89 million and $79 million, respectively, are included in revenues and expenses forGeneration. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $236 million, $238 million and $241 million, respectively, are included in revenues andexpenses for ComEd. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $133 million, $128 million and $129 million, respectively, are included in revenuesand expenses for PECO. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $85 million, $86 million and $82 million are included in revenues and expensesfor BGE, respectively.(d)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: 2015 2014 2013 Revenuesfromexternalcustomers Intersegmentrevenues Totalrevenues Revenuesfromexternalcustomers Intersegmentrevenues Totalrevenues Revenuesfromexternalcustomers Intersegmentrevenues Totalrevenues Mid-Atlantic $5,974 $(74) $5,900 $5,414 $(155) $5,259 $5,261 $(57) $5,204 Midwest 4,712 (2) 4,710 4,488 (13) 4,475 4,298 (28) 4,270 New England 2,217 (5) 2,212 1,468 (46) 1,422 1,279 (42) 1,237 New York 996 (11) 985 846 (3) 843 717 (3) 714 ERCOT 863 (6) 857 938 (3) 935 1,223 (7) 1,216 Other Power Regions 1,182 (80) 1,102 1,379 (70) 1,309 1,084 (116) 968 Total Revenuesfor Reportable Segments $15,944 $(178) $15,766 $14,533 $(290) $14,243 $13,862 $(253) $13,609 Other 3,191 178 3,369 2,860 290 3,150 1,768 253 2,021 Total GenerationConsolidated OperatingRevenues $19,135 $— $19,135 $17,393 $— $17,393 $15,630 $— $15,630 (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues are included on a fully consolidatedbasis.(b)Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.(c)Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $7 million increase to revenues, a $289 million decreaseto revenues, and a $767 million decrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the years endedDecember 31, 2015, 2014, and 2013, respectively, unrealized mark-to-market gains of $203 million, losses of $174 million, and gains of $220 million for the years endedDecember 31, 2015, 2014, and 2013, respectively, and elimination of intersegment revenues.(d)Exelon corrected an error in the December 31, 2014 and December 31, 2013 balances within Intersegment revenues and Revenues from external customers for an overstatementof Intersegment revenues for Reportable Segments of $284 million and 422 (b) (b)(d) (d) (b)(d)(d) (a)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) $252 million for the years ended December 31, 2014 and 2013, respectively, an understatement of Revenues from external customers for Reportable Segments of $284 millionand $252 million for the years ended December 31, 2014 and 2013, respectively, an understatement of Intersegment revenues for Other of $284 million and $252 million for theyears ended December 31, 2014 and 2013, respectively, and an overstatement of Revenues from external customers for Other of $284 million and $252 million for the yearsended December 31, 2014 and 2013, respectively. The error is not considered material to any prior period, and there is no net impact to Total Revenues. Generation total revenues net of purchased power and fuel expense: 2015 2014 2013 RNF fromexternalcustomers IntersegmentRNF TotalRNF RNF fromexternalcustomers IntersegmentRNF TotalRNF RNF fromexternalcustomers IntersegmentRNF TotalRNF Mid-Atlantic $3,556 $15 $3,571 $3,544 $(113) $3,431 $3,287 $(17) $3,270 Midwest 2,912 (20) 2,892 2,607 (8) 2,599 2,606 (20) 2,586 New England 519 (58) 461 450 (99) 351 299 (114) 185 New York 584 50 634 439 44 483 (55) 51 (4) ERCOT 425 (132) 293 573 (256) 317 627 (191) 436 Other Power Regions 440 (190) 250 517 (190) 327 397 (196) 201 Total Revenues net ofpurchased power and fuelexpense for ReportableSegments $8,436 $(335) $8,101 $8,130 $(622) $7,508 $7,161 $(487) $6,674 Other 678 335 1,013 (662) 622 (40) 272 487 759 Total Generation Revenues netof purchased power and fuelexpense $9,114 $— $9,114 $7,468 $— $7,468 $7,433 $— $7,433 (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenue net of purchased power and fuelexpense are included on a fully consolidated basis.(b)Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.(c)Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $8 million increase in RNF, a $124 million decrease inRNF, and a $488 million decrease in RNF for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2015,2014, and 2013, respectively, unrealized mark-to-market gains of $257 million, losses of $591 million, and gains of $504 million for the years ended December 31, 2015, 2014,and 2013, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.(d)Exelon corrected an error in the December 31, 2014 and December 31, 2013 balances within Intersegment RNF and RNF from external customers for an understatement of $8million and an overstatement of $134 million of Intersegment RNF for Reportable Segments for the years ended December 31, 2014 and 2013, respectively, an understatement ofRNF from external customers for Reportable Segments of $11 million and $134 million for the years ended December 31, 2014 and 2013, respectively, an overstatement of $8million and an understatement $134 million of Intersegment RNF for Other for the years ended December 31, 2014 and 2013, respectively, and an overstatement of RNF fromexternal customers for Other of $11 million and $134 million for the years ended December 31, 2014 and 2013, respectively. This also included an understatement of total RNF forReportable Segments and an overstatement of total RNF for Other of $19 million for the year ended December 31, 2014. The error is not considered material to any prior period,and there is no net impact to Generation Total RNF for 2013 or 2014. 423 (b) (b)(d)(d) (b)(d) (d) (a)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. 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, 2015 2014 2013 Operating revenues from affiliates: PECO $1 $1 $10 CENG — 17 56 BGE 4 5 4 Other 4 — — Total operating revenues from affiliates $9 $23 $70 Purchase power and fuel from affiliates: CENG $— $282 $992 Keystone Fuels, LLC — 138 144 Conemaugh Fuels, LLC — 99 98 Safe Harbor Water Power Corp — 12 22 Total purchase power and fuel from affiliates $— $531 $1,256 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 16 Total interest expense to affiliates, net $41 $41 $41 Earnings (losses) in equity method investments: CENG $— $(19) $9 Qualifying facilities and domestic power projects (8) (1) 1 Other $1 $— $— Total earnings (losses) in equity method investments $(7) $(20) $10 424(a)(b)(a) (c)(d)(d)(d)(e)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 2014 Payables to affiliates (current): ComEd Financing III $4 $4 PECO Trust III 1 1 BGE Capital Trust II 3 3 Total payables to affiliates (current) $8 $8 Long-term debt due to financing trusts: ComEd Financing III $205 $205 PECO Trust III 81 81 PECO Trust IV 103 103 BGE Capital Trust II 252 252 Total long-term debt due to financing trusts $641 $641 (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) not sold to third parties. Beginning April 1, 2014, salesto Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.(d)During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power 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. 425Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 2014 2013 Operating revenues from affiliates: ComEd $18 $176 $506 PECO 224 198 405 BGE 502 387 455 CENG — 17 56 BSC 1 1 1 Other 4 — — Total operating revenues from affiliates $749 $779 $1,423 Purchase power and fuel from affiliates: ComEd $— $1 $1 BGE 14 25 13 CENG — 282 992 Keystone Fuels, LLC — 138 144 Conemaugh Fuels, LLC — 99 98 Safe Harbor Water Power Corporation — 12 22 Total purchase power and fuel from affiliates $14 $557 $1,270 Operating and maintenance from affiliates: ComEd $4 $3 $2 PECO 2 2 1 BSC 614 618 571 Total operating and maintenance from affiliates $620 $623 $574 Interest expense to affiliates, net: Exelon Corporate $43 $53 $59 Earnings (losses) in equity method investments CENG $— $(19) $9 Qualifying facilities and domestic power projects (8) (1) 1 Total earnings (losses) in equity method investments $(8) $(20) $10 Capitalized costs BSC $76 $91 $93 Cash distribution paid to member $2,474 $645 $625 Contribution from member $47 $53 $26 426(a)(b)(c)(d)(e)(i)(i) (i) (f) (f) (g)(j) (h) (g)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 2014 Receivables from affiliates (current): ComEd $15 $43 PECO 36 29 BGE 31 40 Other 1 1 Total receivables from affiliates (current) $83 $113 Intercompany money pool (current): Exelon Corporate $1,252 $— Long-term debt due to affiliates (current): Exelon Corporate $— $556 Payables to affiliates (current): Exelon Corporate $16 $12 BSC 78 83 ComEd 9 12 Other 1 — Total payables to affiliates (current) $104 $107 Long-term debt due to affiliates (noncurrent): Exelon Corporate $933 $943 Payables to affiliates (noncurrent): BSC $— $1 ComEd 2,172 2,389 PECO 405 490 Total payables to affiliates (noncurrent) $2,577 $2,880 (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) not sold to third parties. Beginning April 1, 2014, salesto Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. 427(a)(b)(c)(l)(j)(g)(l)(g)(k)(k)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)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.(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 16—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. ComEd The financial statements of ComEd include related party transactions as presented in the tables below: For the Years EndedDecember 31, 2015 2014 2013 Operating revenues from affiliates Generation $4 $4 $3 Purchased power from affiliate Generation $18 $176 $512 Operating and maintenance from affiliate BSC $195 $166 $157 Interest expense to affiliates, net: ComEd Financing III $13 $13 $13 Capitalized costs BSC $103 $77 $69 Cash dividends paid to parent $299 $307 $220 Contribution from parent $202 $273 $— 428 (a) (b) (b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 2014 Prepaid voluntary employee beneficiary association trust $11 $13 Receivable from affiliates (current): Voluntary employee beneficiary association trust $2 $2 Generation 9 12 Exelon Corporate 188 — Total receivable from affiliates (current) $199 $14 Receivable from affiliates (noncurrent): Generation $2,172 $2,389 Exelon Corporate — 182 Total receivable from affiliates (noncurrent) $2,172 $2,571 Payables to affiliates (current): Generation $15 $43 BSC 39 32 ComEd Financing III 4 4 PECO 2 2 Exelon Corporate 2 3 Total payables to affiliates (current) $62 $84 Long-term debt to ComEd financing trust ComEd Financing III $205 $205 (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 13—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.(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. 429 (c) (e) (d) (e)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 financial statements of PECO include related party transactions as presented in the tables below: For the Years EndedDecember 31, 2015 2014 2013 Operating revenues from affiliates: Generation $2 $2 $1 Purchased power from affiliate Generation $220 $194 $392 Operating and maintenance from affiliates: BSC $107 $96 $98 Generation 3 3 3 Total operating and maintenance from affiliates $110 $99 $101 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 $40 $39 $46 Cash dividends paid to parent $279 $320 $332 Contribution from parent $16 $24 $27 December 31, 2015 2014 Prepaid voluntary employee beneficiary association trust $2 $3 Receivable from affiliate (current): ComEd $2 $2 BGE — 1 Total receivable from affiliates (current) $2 $3 Receivable from affiliate (noncurrent): Generation $405 $490 Payables to affiliates (current): Generation $36 $29 BSC 17 20 Exelon Corporate 1 2 PECO Trust III 1 1 Total payables to affiliates (current) $55 $52 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. 430(a) (b)(c) (c) (d)(e) (b) (c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) (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. BGE The financial statements of BGE include related party transactions as presented in the tables below: For the Years EndedDecember 31, 2015 2014 2013 Operating revenues from affiliates: Generation $14 $25 $13 Purchased power from affiliate Generation $498 $382 $452 Operating and maintenance from affiliates: BSC $118 $103 $83 Interest expense to affiliates, net: BGE Capital Trust II $16 $16 $16 Capitalized costs BSC $28 $19 $15 Cash dividends paid to parent $158 $— $— Contribution from parent $7 $— $— December 31, 2015 2014 Prepaid voluntary employee beneficiary association trust $— $1 Payables to affiliates (current): Generation $31 $40 BSC 17 17 Exelon Corporate 1 5 PECO — 1 BGE Capital Trust II 3 3 Total payables to affiliates (current) $52 $66 Long-term debt to BGE financing trust BGE Capital Trust II $252 $252 (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. 431 (a) (b) (c) (c) (d)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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)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. 27. 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 Incomeon CommonStock 2015 2014 2015 2014 2015 2014 Quarter ended: March 31 $8,830 $7,237 $1,366 $168 $693 $90 June 30 6,514 6,024 1,134 842 638 522 September 30 7,401 6,912 1,200 1,738 629 993 December 31 6,702 7,255 707 348 309 18 (a)In the first, second, and third quarter of 2015, Exelon reclassified $(1) million, $7 million, and $2 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, 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.(c)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 Incomeper Basic Share 2015 2014 2015 2014 Quarter ended: March 31 862 858 $0.80 $0.10 June 30 863 860 0.74 0.61 September 30 913 861 0.69 1.15 December 31 921 861 0.34 0.02 Average Diluted SharesOutstanding(in millions) Net Incomeper Diluted Share 2015 2014 2015 2014 Quarter ended: March 31 867 861 $0.80 $0.10 June 30 866 864 0.74 0.60 September 30 915 863 0.69 1.15 December 31 924 868 0.33 0.02 432(a)(b)(a)(b)(a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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: 2015 2014 FourthQuarter ThirdQuarter SecondQuarter FirstQuarter FourthQuarter ThirdQuarter SecondQuarter FirstQuarter High price $31.37 $34.44 $34.98 $38.25 $38.93 $36.26 $37.73 $33.94 Low price 25.09 28.41 31.28 31.71 33.07 30.66 33.11 26.45 Close 27.77 29.70 31.42 33.61 37.08 34.09 36.48 33.56 Dividends 0.310 0.310 0.310 0.310 0.310 0.310 0.310 0.310 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 2015 2014 2015 2014 2015 2014 Quarter ended: March 31 $5,840 $4,390 $719 $(384) $443 $(185) June 30 4,232 3,789 703 441 398 340 September 30 4,768 4,412 622 1,225 377 771 December 31 4,294 4,802 230 (105) 154 (91) (a)In the first, second, and third quarter of 2015, Generation reclassified $(1) million, $7 million, and $1 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, 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. ComEd The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts: Operating Revenues Operating Income Net Income 2015 2014 2015 2014 2015 2014 Quarter ended: March 31 $1,185 $1,134 $230 $238 $90 $98 June 30 1,148 1,128 243 258 99 111 September 30 1,376 1,222 327 287 149 126 December 31 1,196 1,079 217 196 87 73 (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. 433(a)(a)(b)(a)(b)(a)(b)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015 2014 2015 2014 2015 2014 Quarter ended: March 31 $985 $993 $223 $149 $139 $89 June 30 661 656 124 134 70 84 September 30 740 693 154 133 90 81 December 31 645 750 128 156 79 98 BGE The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts: Operating Revenues OperatingIncome Net Incomeattributable toCommon Shareholders 2015 2014 2015 2014 2015 2014 Quarter ended: March 31 $1,036 $1,054 $204 $169 $106 $85 June 30 628 653 99 55 44 16 September 30 725 697 110 102 51 46 December 31 746 761 144 113 74 52 434Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2015, 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. Accordingly, as of December 31, 2015, 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 2015 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. During 2015 management included an assessment of internal controls over financial reporting of Integrys, a business acquired onNovember 1, 2014, that was excluded from management’s prior year evaluation consistent with guidance issued by the Securities and ExchangeCommission that an assessment of internal controls of a recently acquired business may be omitted. The total revenues related to the Integrysbusiness are 7.45% and 11.46%, respectively, and total assets related to Integrys are approximately 0.53% and 1.08%, respectively, of Exelon’sand Generation’s related consolidated financial statement amounts as of and for the year ended December 31, 2015. 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, 2015. Asa result of that assessment, management determined 435Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Table of Contentsthat there were no material weaknesses as of December 31, 2015 and, therefore, concluded that each registrant’s internal control over financialreporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS ANDSUPPLEMENTARY DATA. ITEM 9B.OTHER INFORMATION Exelon, Generation, ComEd, PECO and BGE None. 436Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016. 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 2016 proxy statement(2016 Exelon Proxy Statement) and the ComEd information statement (2016 ComEd Information Statement) to be filed with the SEC beforeApril 29, 2016 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. 437Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 the2016 Exelon Proxy Statement or the ComEd 2016 Information Statement and incorporated herein by reference. 438Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2016 Exelon Proxy Statement or theComEd 2016 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(excluding securitiesreflected incolumn [B]) (Note 3) Equity compensation plans approved by securityholders 29,694,000 $35.67 30,102,000 (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 granted in 2013, 2014 and 2015, the total includes the maximum number of shares that could be granted, if performance, total shareholder return modifier, and individualperformance multipliers were all at maximum, a total of 9,016,000 shares. At target, the number of securities to be issued for such awards is 4,508,000. The deferred stock unitsgranted to directors includes 338,000 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon board of directors, and 102,000 sharesto be issued upon the conversion of stock units held by members of the Exelon board of directors that were earned under a legacy Constellation Energy Group plan. Conversionof stock units to shares will occur after the director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 20—Common Stock of theCombined 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 $46.68.(3)Includes 22,289,000 shares available for issuance from the company’s employee stock purchase plan. No ComEd securities are authorized for issuance under equity compensation plans. 439Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2016Exelon Proxy Statement or the ComEd 2016 Information Statement and incorporated herein by reference. 440Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 2016 in the 2016 Proxy Statement and the 2016 ComEd Information Statement and incorporated herein by reference. 441Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Balance Sheets at December 31, 2015 and 2014 Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013 Notes to Consolidated Financial Statements2. Financial Statement Schedules: Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2015 and 2014 and for the Years EndedDecember 31, 2015, 2014 and 2013 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. 442Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Operating expenses Operating and maintenance $— $9 $9 Operating and maintenance from affiliates 43 38 34 Other 4 3 12 Total operating expenses 47 50 55 Operating loss (47) (50) (55) Other income and (deductions) Interest expense, net (168) (237) (116) Equity in earnings of investments 2,461 1,779 1,903 Interest income from affiliates, net 43 53 36 Other, net (43) (2) (78) Total other income 2,293 1,593 1,745 Income before income taxes 2,246 1,543 1,690 Income taxes (23) (80) (29) Net income $2,269 $1,623 $1,719 Other comprehensive income (loss) Pension and non-pension postretirement benefit plans: Prior service cost (benefit) reclassified to periodic costs $(46) $(30) $— Actuarial loss reclassified to periodic cost 220 147 208 Transition obligation reclassified to periodic cost — — — Pension and non-pension postretirement benefit plan valuationadjustment (99) (497) 669 Unrealized loss on cash flow hedges 9 (148) (248) Unrealized gain on marketable securities — 1 2 Unrealized gain on equity investments (3) 8 106 Unrealized loss on foreign currency translation (21) (9) (10) Reversal of CENG equity method AOCI — (116) — Other comprehensive income (loss) 60 (644) 727 Comprehensive income $2,329 $979 $2,446 See Notes to Financial Statements 443Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 2013 Net cash flows provided by operating activities $3,071 $806 $1,053 Cash flows from investing activities Return on investment of direct financing lease termination — 335 — Changes in Exelon intercompany money pool (1,217) (83) (60) Note receivable from affiliates 550 — 484 Capital expenditures — 1 — Change in restricted cash — — 38 Investment in affiliates (212) (70) (38) Other investing activities (55) (126) 15 Net cash flows provided by (used in) investing activities (934) 57 439 Cash flows from financing activities Changes in short-term borrowings — — 10 Issuance of long-term debt 4,200 1,150 — Retirement of long-term debt (2,263) (23) (450) Issuance of common stock 1,868 — — Dividends paid on common stock (1,105) (1,065) (1,249) Proceeds from employee stock plans 32 35 47 Other financing activities (58) (84) (6) Net cash flows provided by (used in) financing activities 2,674 13 (1,648) Increase (decrease) in cash and cash equivalents 4,811 876 (156) Cash and cash equivalents at beginning of period 879 3 159 Cash and cash equivalents at end of period $5,690 $879 $3 See Notes to Financial Statements 444Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 ASSETS Current assets Cash and cash equivalents $5,690 $879 Accounts receivable, net Other accounts receivable 272 209 Accounts receivable from affiliates 20 24 Notes receivable from affiliates 1,478 818 Regulatory assets 241 254 Other 5 22 Total current assets 7,706 2,206 Property, plant and equipment, net 53 54 Deferred debits and other assets Regulatory assets 3,072 3,186 Investments in affiliates 26,119 26,670 Deferred income taxes 2,036 2,147 Non-pension postretirement benefit asset 108 — Notes receivable from affiliates 933 943 Other 404 149 Total deferred debits and other assets 32,672 33,095 Total assets $40,431 $35,355 See Notes to Financial Statements 445Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term borrowings $188 $— Long-term debt due within one year 60 1,409 Accounts payable 5 2 Accrued expenses 440 25 Regulatory liabilities 63 51 Pension obligations 52 45 Other 1 30 Total current liabilities 809 1,562 Long-term debt 6,017 2,818 Long-term debt to affiliate — 182 Deferred credits and other liabilities Regulatory liabilities 31 37 Pension obligations 7,520 7,638 Non-pension postretirement benefit obligations — 16 Deferred income taxes 134 93 Other 122 398 Total deferred credits and other liabilities 7,807 8,182 Total liabilities 14,633 12,744 Commitments and contingencies Shareholders’ equity Common stock (No par value, 2000 shares authorized, 920 shares and 860 shares outstanding at December 31,2015 and 2014, respectively) 18,678 16,709 Treasury stock, at cost (35 shares at December 31, 2015 and 2014, respectively) (2,327) (2,327) Retained earnings 12,068 10,910 Accumulated other comprehensive loss, net (2,624) (2,684) Total shareholders’ equity 25,795 22,608 BGE preference stock not subject to mandatory redemption 3 3 Total liabilities and shareholders’ equity $40,431 $35,355 See Notes to Financial Statements 446Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additionalinformation on the Merger Agreement with PHI. For BGE’s debt, the difference between fair value and book value of BGE’s assets acquired and liabilities assumed is recorded as aregulatory asset at Exelon Corporate as Exelon did not apply push-down accounting to BGE as part of the 2012 Constellation Merger. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the fair value of BGE long-termdebt regulatory asset. 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, 2015 and December 31, 2014. 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, 2015, Exelon Corporation had available capacity under those commitmentsof $474 million. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further informationregarding Exelon Corporation’s credit agreement. 447Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Long-Term Debt The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2015 and December 31, 2014: MaturityDate December 31, Rates 2015 2014 Long-term debt Junior subordinated notes 6.5% 2024 $1,150 $1,150 Contract payment—junior subordinated notes 2.5% 2017 64 108 Senior unsecured notes 1.6% – 7.6% 2017-2045 4,639 2,658 Total long-term debt 5,853 3,916 Unamortized debt discount and premium, net (4) 1 Unamortized debt issuance costs (47) (23) Fair value adjustment of consolidated subsidiary 275 333 Long-term debt due within one year (60) (1,409) Long-term debt $6,017 $2,818 (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 2016, 2017, 2018, 2019, 2020 and thereafter are as follows: 2016 $45 2017 569 2018 — 2019 — 2020 1,450 Remaining years 3,789 Total long-term debt $5,853 4. Commitments and Contingencies See Note 23—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. 448(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 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) 2015 2014 2013 Operating and maintenance from affiliates: BSC $43 $38 $34 Interest income from affiliates, net: Generation $43 $53 $36 Equity in earnings of investments: Exelon Energy Delivery Company, LLC $1,079 $958 $834 Exelon Ventures Company, LLC — 926 1,076 UII, LLC 20 (6) (2) Exelon Transmission Company, LLC (8) (7) (5) Exelon Enterprise (1) (1) — Generation 1,371 (91) — Total equity in earnings of investments $2,461 $1,779 $1,903 Cash contributions received from affiliates $3,209 $1,370 $1,175 449 (a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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) 2015 2014 Accounts receivable from affiliates (current): BSC $— $2 Generation 16 12 ComEd 2 3 PECO 1 2 BGE 1 5 Total accounts receivable from affiliates (current) $20 $24 Notes receivable from affiliates (current): BSC $226 $262 Generation 1,252 556 Total receivable from affiliates (current): $1,478 $818 Investments in affiliates: BSC $191 $193 Exelon Energy Delivery Company, LLC 14,163 13,590 UII, LLC 102 130 Exelon Transmission Company, LLC 3 1 Voluntary Employee Beneficiary Association trust 7 9 Exelon Enterprises 22 23 Generation 11,637 12,720 Other (6) 4 Total investments in affiliates $26,119 $26,670 Notes receivable from affiliates (non-current): Generation $933 $943 Notes payable to affiliates (current): ComEd $188 $— Long-term debt to affiliates (non-current): ComEd $— $182 (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 Company, LLC, andExelon Consolidations are now directly owned Exelon Corporate investments as of December 31, 2014.(d)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. 450(a)(a)(d) (a) (b)(d)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Allowance for uncollectible accounts $311 $113 $27 $167 $284 Deferred tax valuation allowance 50 — (27) 10 13 Reserve for obsolete materials 95 10 2 2 105 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 (a)Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $8 million, and $9 million for the years endedDecember 31, 2015, 2014, and 2013, respectively.(b)Includes charges for late payments and non-service receivables.(c)Write-off of individual accounts receivable. 451(a)(b)(c)(a)(b)(c) (a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Balance Sheets at December 31, 2015 and 2014 Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 2015, 2014 and 2013 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 452Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Allowance for uncollectible accounts $60 $22 $— $5 $77 Deferred tax valuation allowance 48 — (27) 10 11 Reserve for obsolete materials 93 9 — — 102 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 453Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Balance Sheets at December 31, 2015 and 2014 Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013 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 454Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Allowance for uncollectible accounts $84 $39 $18 $66 $75 Reserve for obsolete materials 2 1 2 2 3 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 (a)Primarily charges for late payments and non-service receivables.(b)Write-off of individual accounts receivable. 455(a)(b)(a)(b)(a)(b)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Balance Sheets at December 31, 2015 and 2014 Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013 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 456Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Allowance for uncollectible accounts $100 $37 $9 $63 $83 Reserve for obsolete materials 1 — — — 1 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 (a)Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $8 million, and $9 million for the years endedDecember 31, 2015, 2014, and 2013, respectively.(b)Primarily charges for late payments.(c)Write-off of individual accounts receivable. 457 (a)(b)(c) (a)(b)(c) (a)(b)(c)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10, 2016 of PricewaterhouseCoopers LLP Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Balance Sheets at December 31, 2015 and 2014 Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013 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 458Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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, 2015 Allowance for uncollectible accounts $67 $15 $— $33 $49 Deferred tax valuation allowance 1 — — — 1 Reserve for obsolete materials — — — — — 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 (a)Write-off of individual accounts receivable.(b)Primarily charges for late payments. 459(b)(a)(b)(a)(a)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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).2-10-2 Amended and Restated Agreement and Plan of Merger, dated as of July 18, 2014, among Pepco Holdings, Inc., ExelonCorporation and Purple Acquisition Corp. (File No. 001-16169, Form 8-K dated July 21, 2014, Exhibit 2.1). 460Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description2-10-3 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, Form10-Q for the quarter ended September 30, 2008, Exhibit 3-1-2).3-2 Exelon Corporation Amended and Restated Bylaws, effective as of March 12, 2012 (File No. 001-16169, Form 8-K dated March14, 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 (FileNo. 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 Companypreference stock known as the “$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the“$2.425 Cumulative Preference Stock” (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2).3-6 Commonwealth Edison Company Amended and Restated By-Laws, Effective January 23, 2006 As Further Amended January28, 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 ExhibitNo. 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 andElectric Company, File No. 1-1910).3-11 Bylaws of Baltimore Gas and Electric Company, as amended and restated as of May 10, 2012. (File No. 1-16169, 2013 Form10-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 PECOEnergy Company) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee),(Registration No. 2-2281, Exhibit B-1).4-1-2 Reserved. 461Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description4-1-3 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 dated September23, 2013 4.1 September 1, 2014 000-16169, Form 8-K dated September15, 2014 4.1 September 15, 2015 000-16844, Form 8-K dated October 5,2015 4.14-2 Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-206474, Form S-3, Prospectus).4-3 Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, ascurrent successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1,1944. (Registration No. 2-60201, Form S-7, Exhibit 2-1). 462Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description4-3-1 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 13, 2003 001-01839, Form 8-K datedJanuary 22, 2003 4-4 February 22, 2006 001-01839, Form 8-K dated March 6,2006 4.1 August 1, 2006 001-01839, Form 8-K dated August 28,2006 4.1 September 15, 2006 001-01839, Form 8-K dated October 2,2006 4.1 March 1, 2007 001-01839, Form 8-K dated March 23,2007 4.1 August 30, 2007 001-01839, Form 8-K dated September10, 2007 4.1 December 20, 2007 001-01839, Form 8-K dated January 16,2008 4.1 463Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 Dated as of File Reference Exhibit No. March 10, 2008 001-01839, Form 8-K dated March 27,2008 4.1 July 12, 2010 001-01839, Form 8-K dated August 2,2010 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 001-01839, Form 8-K dated November10, 2014 4.1 February 18, 2015 001-01839, Form 8-K dated March 2,2015 4.1 November 4, 2015 001-01839, Form 8-K dated November19, 2015 4.1Exhibit No. Description4-3-2 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 (File No. 1-1839, 2001 Form 10-K, Exhibit 4-4-2).4-3-3 Instrument dated as of January 31, 1996, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1,1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit 4-29).4-4 Indenture dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A. (U.S. Bank 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. BankNational 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).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). 464Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description4-12 Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and U.S. Bank National Association,as Trustee, dated as of June 24, 2003 (File No. 0-16844, June 30, 2003 Form 10-Q, Exhibit 4.2).4-13 PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S.Bank Trust National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and CharlesS. 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 $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation (File No. 1-16169, Form 8-K dated June 9, 2005, Exhibit 99.3).4-16 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).4-17 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).4-18 Form of 6.25% Exelon Generation Company, LLC Senior Note due 2039 (File 333-85496, Form 8-K dated September 23, 2009,Exhibit 4.2).4-19 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).4-20 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).4-21 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.)4-22 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).4-23 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).4-24 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).4-25 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).4-26 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). 465Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description4-27 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).4-28 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).4-29 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).4-30 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 and 1-1910).4-31 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).4-32 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).4-33 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).4-34 Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K datedJune 30, 2008, filed by Constellation Energy Group, Inc., File No. 1-12869).4-35 Amendment to Replacement Capital Covenant, dated as of March 12, 2012, amending the Replacement Capital Covenant, datedas of June 27, 2008 (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 99.4).4-36 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). 466Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description4-37 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).4-38-1 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).4-38-2 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).4-38-3 Form of 2.50% Notes due 2024 (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1).4-38-4 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).4-38-5 Form of Remarketing Agreement (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.5).4-38-6 Form of Corporate Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.6).4-38-7 Form of Treasury Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.7).4-39-1 Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, NationalAssociation, as trustee (incorporated herein by reference to Exhibit 4.1 to Exelon Corporation’s Current Report on Form 8-K, filed onJune 11, 2015).4-39-2 First Supplemental Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon TrustCompany, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to Exelon Corporation’s Current Reporton Form 8-K, filed on June 11, 2015).4-39-3 Second Supplemental Indenture, dated as of December 2, 2015, among Exelon Corporation and The Bank of New York MellonTrust Company, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Exelon Corporation’s CurrentReport on Form 8-K, filed on December 2, 2015).4-39-4 Registration Rights Agreement, dated as of December 2, 2015, among Exelon Corporation, Barclays Capital Inc. and Goldman,Sachs & Co. (incorporated herein by reference to Exhibit 1.1 to Exelon Corporation’s Current Report on Form 8-K, filed onDecember 2, 2015).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). 467Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description10-3 Form of Exelon Corporation Unfunded Deferred Compensation Plan for Directors (as amended and restated Effective March 12,2012). *10-4 Reserved.10-5 Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form10-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 effective January 1, 2009 * (File No. 001-16169. 2008Form 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).10-21-1 Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective November 1, 2015) 468Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description10-22 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).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, 2014.10-34-2 Form of Exelon Corporation Long-Term Incentive Program, as amended and restated as of January 1, 2015.10-34-3 Amendment Number Two to the Exelon Corporation 2011 Long-Term Incentive Plan (As Amended and Restated Effective January21, 2014), Effective October 26, 2015.10-35 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 (FileNo. 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). 469Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description10-39 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, Form 8-Kdated August 10, 2013, Exhibit No. 99-1).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 Exhibit No.10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, filed by Constellation Energy Group, Inc.,File Nos. 1-12869 and 1-1910).10-49 Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated. * (Designated as Exhibit No.10(a) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed by Constellation Energy Group,Inc., File Nos. 1-12869 and 1-1910).10-50 Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. * (Designated as Exhibit No. 10(b) 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). 470Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description10-51 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).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). 471Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description10-62 Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.),E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).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, thefinancial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.3).10-71-5 Amendment No. 3 to Credit Agreement, dated May 30, 2014, among PECO Energy Company, as Borrower, the financialinstitutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form8-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. 472Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description12-4 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.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 Linda P. Jojo24-9 Robert J. Lawless24-10 Richard W. Mies24-11 John W. Rogers, Jr.24-12 Mayo A. Shattuck III24-13 Stephen D. Steinour Power of Attorney (Commonwealth Edison Company)24-14 James W. Compton24-15 Christopher M. Crane24-16 A. Steven Crown24-17 Nicholas DeBenedictis24-18 Peter V. Fazio, Jr.24-19 Michael Moskow24-20 Denis P. O’Brien 473Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description24-21 Anne R. Pramaggiore24-22 Reserved. Power of Attorney (PECO Energy Company)24-23 Craig L. Adams24-24 Christopher M. Crane24-25 M. Walter D’Alessio24-26 Nicholas DeBenedictis24-27 Nelson A. Diaz24-28 Rosemarie B. Greco24-29 Charisse R. Lillie24-30 Denis P. 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 P. 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 for theyear 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, LLC 474Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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. Description32-4 Filed by Bryan P. Wright for Exelon Generation Company, LLC32-5 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. 475Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10th day of February, 2016. 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 10th day of February, 2016. Signature Title/S/ CHRISTOPHER M. CRANE Christopher M. Crane President and Chief Executive Officer(Principal Executive Officer) and Director/S/ JOHNATHAN W. THAYER Jonathan W. Thayer Senior Executive Vice President and Chief Financial Officer(Principal Financial Officer)/S/ DUANE M. DESPARTE Duane M. DesParte Senior Vice President and Corporate Controller (Principal AccountingOfficer) 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 DeBenedictisPaul L. Joskow Linda P. JojoRobert J. LawlessRichard W. MiesJohn W. Rogers, Jr.Mayo A. Shattuck IIIStephen D. Steinour By: /S/ DARRYL M. BRADFORD February 10, 2016Name: Darryl M. Bradford 476Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10th day of February, 2016. 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 10th day of February, 2016. 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 (PrincipalFinancial Officer)/S/ ROBERT M. AIKEN Robert M. Aiken Vice President and Controller (Principal Accounting Officer) 477Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10th day of February, 2016. 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 10th day of February, 2016. 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 10, 2016Name: Anne R. Pramaggiore 478Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10th day of February, 2016. PECO ENERGY COMPANYBy: /s/ CRAIG L. ADAMS Name: Craig L. AdamsTitle: 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 10th day of February, 2016. Signature Title/s/ CRAIG L. ADAMS Craig L. Adams President and Chief Executive Officer (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 Charisse R. LillieNicholas DeBenedictis Denis P. O’BrienNelson A. Diaz Ronald RubinRosemarie B. Greco By: /s/ CRAIG L. ADAMS February 10, 2016Name: Craig L. Adams 479Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the 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 10th day of February, 2016. 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 10th day of February, 2016. 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 10, 2016Name: Calvin G. Butler, Jr. 480Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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”) to elect to defer receipt of directors’ fees. The Plan as set forth herein is an amendment and restatement of the Plan as originally adopted effectiveOctober 20, 2000 and previously amended and restated as of January 1, 2009 and January 1, 2011, and is a successor to the PECO Energy CompanyUnfunded Deferred Compensation 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 suchother individual or individuals as designated by the Board of Directors of Exelon (the “Exelon Board”). The Secretary shall interpret the Plan and establishsuch rules and regulations of plan administration that he or she deems appropriate. The cost of plan administration shall be paid by Exelon and itsparticipating subsidiaries, 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 thePlan. Effective as of January 1, 2011, all Directors of Commonwealth Edison Company (“ComEd”) and PECO Energy Company (“PECO”) who are not full-time employees of Exelon or its subsidiaries shall also be eligible to participate in the Plan. In addition, effective as of March 12, 2012, all Directors ofBaltimore Gas and Electric Company (“BGE”) who are not full-time employees of Exelon or its subsidiaries shall also be eligible to participate in the Plan.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 aportion of his or her directors’ feesSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.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 suchcalendar year, by filing a written Director’s deferral agreement form with the Secretary with respect to each such Board on which the Director serves. ADirector who first becomes eligible to participate in the Plan after the first day of any calendar year shall be permitted to make the election described in thisSection 3 not later than 30 days after becoming eligible to participate in the Plan, and such election shall apply only to directors’ fees earned during theremainder of such calendar year. In all events, each deferral election made under this Plan shall apply only to fees earned after the date of such election.Deferred amounts under the Plan, together with deferred amounts and attributable earnings under the Prior Plan, shall be credited to a deferral account in theparticipant’s name (“Deferral Account”) for later distribution. Each participant’s Deferral Account shall be a bookkeeping entry only, and none of 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 times remainunrestricted 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,from among the investment funds available from time to time under the Exelon Corporation Employee Savings Plan (the “Savings Plan”), the investmentfunds in which all or part of his or her Deferral Account shall be deemed to be invested.(2) The participant shall make an investment designation in the form and manner prescribed by the Secretary, which shallremain effective until another valid -2-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.designation has been made by the participant as herein provided. The Secretary may, but need not, permit separate investment designations with respect toamounts attributable to fees earned with respect to service on each Board. The participant may amend his or her investment designation at such times and insuch manner as prescribed by the Secretary. A timely change to the participant’s investment designation shall become effective as soon as administrativelypracticable 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 orher investment 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 invested in thedefault investment fund then in effect under the Savings Plan. The Deferral Accounts maintained pursuant to the Plan are for bookkeeping purposes only andExelon 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 theaggregate 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 be distributedto 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 amounts attributable to feesearned with respect to service on a Board at the time such Director makes his or her initial deferral election under the Plan with respect to his or her service onsuch Board (provided that a Director who participated in the Plan prior to January 1, 2009 and had not commenced distributions must have submitted suchform 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 of distributionsunder the Plan on or before December 31, 2007 was permitted to submit a Benefit Distribution Election Form on or before June 30, 2007 which provided forthe 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 sumpayment 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 any payment thatotherwise 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), andextended in the preamble to regulations proposed under Section 409A of the Code and IRS Notice 2006-79, which permits participants in deferredcompensation 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 with procedures prescribedby the Secretary; provided that, in accordance with Section 409A of the Code, any such change in a distribution election (i) shall not be effective until 12months after it is submitted to the Secretary, (ii) must be submitted to the Secretary at least 12 months prior to the date on which such distributions werepreviously scheduled to commence and (iii) must provide for distributions to commence at least five years after the date on which such distributions werepreviously scheduled to commence. No more than one such election change shall be permissible with respect to the portion of a Director’s accountattributable to service with any Board. -5-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 her DeferralAccount after the participant’s death. The beneficiaries, and any priority or allocation between them, shall be designated in the manner specified by theSecretary. 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 in excess ofthe balance of his or her Deferral Account) sufficient to meet an unforeseeable emergency. An “unforeseeable emergency” means (i) a severe financialhardship 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) of theDirector, (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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Deferral Accountmay not be voluntarily or involuntarily assigned or alienated. In cases of marital dispute, Exelon will observe the terms of the Plan unless and until ordered todo otherwise pursuant to a domestic relations order, as defined in Section 414(p)(1)(B) of the Code. As a condition of participation, a participant agrees tohold Exelon harmless from any claim that arises out of Exelon’s obeying the terms of a domestic relations order, whether such order effects a judgment ofsuch 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 asotherwise provided herein or as permitted under Section 409A of the Code, no such action shall result in the distribution of amounts credited to the DeferralAccounts of any participant in any manner other than is provided in the Plan, nor shall such action reduce the availability of amounts previously deferred. Tothe extent permitted by Section 409A, the Exelon Board may, in its discretion, terminate the Plan with respect to Exelon, ComEd, PECO and/or BGE andaccelerate 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 pursuant to 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) thecalendar 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 promulgated under Section409A 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 of Section409A 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 applicable federallaw. EXELON CORPORATION Executive Vice President -8-Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10.21.1EXELON CORPORATIONSENIOR MANAGEMENTSEVERANCE PLAN(As Amended and Restated)Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 CORPORATIONSENIOR MANAGEMENT SEVERANCE PLAN(As Amended and Restated) 1.PURPOSE OF THE PLANThe Exelon Corporation Senior Management Severance Plan, as amended and restated herein (the “Plan”), is effective as of November 1, 2015 (the“Effective Date”) except as otherwise specifically provided herein, and supersedes in its entirety all prior versions of the Plan with respect to terminations ofemployment occurring any time on or after the Effective Date (or such other date as set forth herein). The Plan provides severance benefits to eligibleexecutives of Exelon Corporation (“Exelon”) and its subsidiaries of which Exelon owns at least 80% of the outstanding voting power that are designated bythe Plan Administrator as participating employers in the Plan (Exelon and such subsidiaries jointly and severally referred to as the “Company”) who submit aNotice of Termination or who are notified of their termination of employment on or after the Effective Date (or such other date as set forth herein), and toprovide additional protection in the event of a Change in Control of Exelon or an Imminent Control Change of Exelon. 2.ELIGIBILITY 2.1.Eligibility in General. Subject to the remaining provisions of this Section 2.1, eligibility to participate in the Plan is limited to each employeeof the Company whose position is in Salary Band E09 (or equivalent executive grade) or above (an “Executive”) who executes and returns tothe Company by the later of 90 days after becoming an Executive, or 90 days after delivery thereof to the Executive, non-competition, non-solicitation, confidential information and intellectual property covenants (“Restrictive Covenants”) which are acceptable to Exelon and areeither substantially in the form attached hereto and made a part hereof as Exhibit I (as may be modified from time to time by Exelon in its solediscretion) or set forth in another agreement between the Company and the Executive. Notwithstanding any provision of the Plan to thecontrary, eligibility for benefits under the Plan shall be subject to the provisions of any agreement (including but not limited to an offer ofemployment or grant instrument) between an Executive and the Company providing that that such Executive would be ineligible for (orwaives) all or a portion of the benefits under the Plan or “change in control” benefits in the event of a termination of employment, or underwhich the Executive had agreed, prior to the Applicable Trigger Date, to terminate his or her employment. 2.2.Eligibility Under Section 4. Subject to Section 2.1, each Executive shall be eligible for the benefits provided under Section 4 hereof in theevent such Executive has a Termination of Employment; provided, however, that any Executive whose Termination of Employment iscovered under Section 5 hereof or a change in control agreement entered into between such Executive and the Company (an “IndividualChange in Control Agreement”), or who is an interim employee separating under the change in control provisions of another severanceSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. plan, shall not be eligible for benefits under Section 4, except as expressly provided in Section 5 or such Individual Change in ControlAgreement (which expressly refers to the benefits under Section 4 of this Plan). 2.3.Eligibility Under Section 5. Eligibility for the benefits provided under Section 5 hereof due to a Termination of Employment during a Post-Change Period or an Imminent Control Change Period shall be subject to Section 2.1, and shall be limited to persons who are Executivesimmediately prior to the Applicable Trigger Date and who are not subject to Individual Change in Control Agreements. 3.PARTICIPATIONEach eligible Executive shall become a participant in the Plan (“Participant”) upon his or her execution of a separation agreement with the Companyin such form as the Company, in its sole discretion, shall require or permit (the “Severance Agreement”), provided such Severance Agreement is executed notlater than 45 days after the Executive’s Termination Date. Notwithstanding anything herein to the contrary, each Executive shall also be required to execute,not later than 45 days after the Executive’s Termination Date, a waiver and release of claims against the Company (“Waiver and Release”) which issubstantially in the form attached hereto and made a part hereof as Exhibit II, as may from time to time be modified by the Company in its sole discretion. AnExecutive’s right to the payments and benefits under this Plan shall be contingent upon (a) Executive having timely executed and delivered to the Companythe Severance Agreement, Waiver and Release and Restrictive Covenants, (b) Executive not revoking the Waiver and Release and (c) Executive not violatingany of Executive’s on-going obligations under the Plan, the Waiver and Release and the Restrictive Covenants. To the extent that the Company makespayments and provides benefits to an Executive prior to receipt of the Waiver and Release and/or the expiration of the revocation period and the Executiveeither does not timely execute and deliver the Waiver and Release to the Company or revokes the Waiver and Release in accordance with its terms, Executiveshall pay to the Company within 10 days following the expiration of the 45-day consideration period or the date such release was revoked, a lump sumpayment of all payments and the value of all benefits received by Executive to date hereunder. 4.BENEFITSA Participant described in Section 2.2 shall be entitled to all Accrued Obligations and, subject to Section 6, benefits pursuant to this Section 4 uponthe Participant’s Termination of Employment. 4.1.Severance Pay. (a)In General. Each Participant other than a Participant described in Section 4.1(b) shall receive severance pay at a monthly rate equalto 1/12 of the sum of (a) the Participant’s annual base salary in effect as of the date of Termination of Employment, plus, if theExecutive is a participant in the Annual Incentive Award Plan with respect to the year in which the Termination Date occurs, (b) theSeverance Incentive. Subject to Section 13.13 below, payment shall be made in regular payroll installments for the 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. duration of the applicable Salary Continuation Period, as indicated below, commencing no later than the second paydate whichoccurs after the Participant’s Termination Date. Payment will be made in accordance with the Company’s normal payroll practices,net of applicable taxes and other deductions. Participant Level Salary Continuation Period Senior Executive Management 24 months Senior Vice Presidents of Exelon 18 months Other Executives 15 months (b)Participants Employed for Less Than Two Years. Each Participant who has been continuously employed by the Company for lessthan twenty-four months as of the Participant’s Termination Date shall receive severance pay at a monthly rate equal to 1/12 of theParticipant’s annual base salary in effect as of the Termination Date. Subject to Section 13.13 below, payment shall be made inregular payroll installments for the duration of the applicable Salary Continuation Period, as indicated below, commencing no laterthan the second paydate which occurs after the Participant’s Termination Date. Payment will be made in accordance with theCompany’s normal payroll practices, net of applicable taxes and other deductions. Participant Level Salary Continuation Period Senior Executive Management 18 months (12 months if employed < 12 months)Other Executives 12 months (6 months if employed < 12 months) 4.2.Annual Incentive Awards. Each Participant who is a participant in the Annual Incentive Award Plan for the year in which the TerminationDate occurs shall receive an Annual Incentive which shall be prorated by multiplying the amount of such Annual Incentive by a fraction thenumerator of which is the number of days elapsed during such year as of the Participant’s Termination Date and the number of days in the yearin which Termination Date occurs. Payment of Annual Incentives under this Section 4.2 shall be made in a lump sum net of applicable taxesand other deductions at the time awards under the Annual Incentive Award Plan are paid to active employees for such performance period (butnot later than March 15 of the year following the last day of such performance period), and 3Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. shall be considered a “short-term deferral” within the meaning of Section 409A of the Code. A Participant who is not a participant in theAnnual Incentive Award Plan for the year in which the Termination Date occurs shall not be entitled to an Annual Incentive, and the amount(if any) payable under any other Incentive Plan for such year shall be determined by the Company in its sole discretion. 4.3.Stock Options. No Participant shall be entitled to participate in any new grants of Stock Options (as defined in Section 5.1(b)) made after suchParticipant’s notification of his or her Termination of Employment. Except as provided below, any Stock Options previously granted to theParticipant shall be exercisable only to the extent such Stock Options are exercisable as of the date of such Participant’s Termination Date andshall thereafter be exercised in accordance with the provisions of the LTIP. Stock Options which remain unexercisable as of the Participant’sTermination Date shall be forfeited. Notwithstanding the preceding, if, as of the last day of the Salary Continuation Period, such Participanthas attained at least age 50 ( age 55 with respect to Stock Options granted on or after January 1, 2013) and completed at least 10 years ofservice as defined under the tax-qualified defined benefit plan maintained by Exelon in which the Executive is a participant (the “PensionPlan”) or SERP, then any Stock Options granted to such Participant which have not become exercisable prior to the Participant’s TerminationDate shall (i) become fully vested, and (ii) remain exercisable until the fifth anniversary of the Termination Date or, if earlier, the optionexpiration date, provided that this Section 4.3 shall not limit the right of the Company to cancel the Stock Options in connection with acorporate transaction pursuant to the terms of the LTIP. 4.4.Other Awards. Awards of Performance Shares, Restricted Stock (as defined in Sections 5.1(c) and 5.1(d), respectively) and/or CashPerformance Awards, as applicable, shall be payable to a Participant solely to the extent provided under the terms of such awards and theapplicable plan under which such awards are granted; provided, however, that to the extent the Company determines that a Participant is aSpecified Employee and that any such payment is deferred compensation, each within the meaning of Section 409A of the Code, suchpayment shall not be made prior to the earlier to occur of (i) the six-month anniversary of the Termination Date or (ii) the date of theParticipant’s death. 4.5.Health Care Coverage. During the Salary Continuation Period, a Participant (and his or her dependents) shall be eligible to participate in thehealth care plans under which they were covered immediately prior to his or her Termination of Employment, in accordance with and subjectto the terms and conditions of such plans as in effect from time to time. The Participant’s out of pocket costs (including premiums, deductiblesand co-payments) for such coverage shall be the same as that in effect from time to time for active peer employees during such period.Coverage under this Paragraph 4.5 shall be provided for the duration of the Salary Continuation Period in lieu of continuation coverage underSection 4980B of the Code and Section 601 to 609 of ERISA (“COBRA”) for the same period. At the end of the Salary Continuation Period,COBRA continuation coverage may be elected for the remaining balance of the statutory coverage 4Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. period, if any; provided, however that a Participant who, as of the last day of the Salary Continuation Period, has attained at least age 50 andcompleted at least 10 years of service (or who has completed such other age and service requirement then in effect under the ExelonCorporation Severance Benefit Plan or any successor plan as of the relevant time set forth in such plan) under the terms of the Pension Plan (orwho, pursuant to the terms of an offer of employment or employment agreement or under any provision of the Pension Plan or SERP, iscredited with a number of additional years of age and/or service that would enable such Participant to satisfy the above eligibilityrequirements) shall be entitled to elect such Company group health care programs for retirees as are in effect as of the Termination Date andare applicable to such Participant by the programs’ eligibility terms and conditions as though such Participant had attained such programs’age and service requirements. The eligibility for coverage and availability of programs or plans, the amounts charged for coverage, and theother terms, conditions and limitations under the Company’s group health care programs or plans shall remain subject to the Company’s rightto amend, change or terminate such programs or plans at any time. 4.6.SERP / Other Deferred Compensation. For purposes of the Participant’s SERP benefit, the Salary Continuation Period shall be taken intoaccount as service solely for purposes of determining whether the Participant is vested (i.e., 3 or 5 years of service) and, to the extent relevantunder the Pension Plan covering the Participant, the amount of the Participant’s regular accrued benefit, but not for purposes of determiningeligibility for early retirement benefits (including any social security supplement) or any other purpose. In determining the amount of theParticipant’s vested benefit, if any, the severance payments made under Section 4.1 shall be taken into account as if such payments werenormal base salary and incentive payments. Payment shall be made in accordance with the SERP and the Participant’s distribution election ineffect thereunder as of the Termination Date (or, if no affirmative election is in effect as of such date, the default election applicable to theParticipant). All amounts previously deferred by, or accrued to the benefit of, such Participant under the Exelon Corporation DeferredCompensation Plan, the Exelon Corporation Stock Deferral Plan or the Constellation Energy Group, Inc. Nonqualified DeferredCompensation Plan shall, to the extent vested, be paid in accordance with the Participant’s distribution election in effect thereunder as of theTermination Date (or, if no affirmative election is in effect as of such date, the default election applicable to the Participant). 4.7.Life Insurance and Disability Coverage. A Participant shall be eligible for continued coverage under the applicable basic life insurance andlong term disability plans sponsored by the Company (or other equivalent coverage or benefits) shall be extended to each Participant throughthe last day of the Salary Continuation Period applicable to such Participant on the same terms and subject to the same terms and conditionsas are applicable to active peer employees (including, without limitation, submission of proof by an Executive who seeks long term disabilitybenefits that such Executive would have satisfied the conditions for such benefits had the Executive been an employee during the SalaryContinuation Period and terminated employment on or before the last day of such period). 5Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. 4.8.Executive Perquisites. Executive perquisites shall terminate effective as of the Participant’s Termination Date, and any Company-ownedproperty shall be required to be returned to the Company no later than such date. 4.9.Outplacement and Financial Counseling Services. Each Participant shall be entitled to outplacement services at the expense of the Companyfor the twelve month period following the Termination Date, and subject to such terms and conditions as the Plan Administrator, in its solediscretion, determines are appropriate. No cash shall be paid in lieu of such fees and costs. 4.10.Restrictions on In-Kind Benefits. The in-kind benefits provided under each of Sections 4.5, 4.7 and 4.8 during any calendar year shall notaffect the benefits to be provided under such section in any subsequent calendar year. The right to such benefits shall not be subject toliquidation or exchange for any other benefit 4.11.Other Coverage. Notwithstanding the foregoing, if such Participant is eligible to obtain a specific type of coverage under welfare plan(s)sponsored by another employer of such Participant (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits,group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if such Participant is so eligible), then theCompany shall not be obligated to provide any such specific type of coverage. The Participant shall promptly notify the Plan Administratorof any such coverage. 5.CHANGE IN CONTROL BENEFITSA Participant described in Section 2.3 shall be entitled to all Accrued Obligations and, subject to Section 6, benefits pursuant to this Section 5 if such aParticipant has a Termination of Employment during a Post-Change Period or Imminent Control Change Period, and such Participant shall not be eligible forbenefits under Section 4 unless so expressly provided in this Section 5. 5.1.Termination During a Post-Change Period. If, during a Post-Change Period, an eligible Executive has a Termination of Employment andbecomes a Participant, the Company’s sole obligations under Section 4 and Sections 5.1 and 5.2 shall be as set forth in this Section 5.1(subject to Sections 5.3, 5.5, 5.6 and 6.0. (a)Severance Payments. The Company shall pay or provide (or cause to be provided) to such Participant, according to the paymentterms set forth in Section 5.3 below, the following: (i)Annual Incentive for Year of Termination. An amount equal to the Annual Incentive applicable to such Participant under theIncentive Plan for the performance period in which the Termination Date occurs; 6Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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)Deferred Compensation and Non-Qualified Defined Contribution Plans. All amounts previously deferred by, or accrued to thebenefit of, such Participant under the Exelon Corporation Deferred Compensation Plan, the Exelon Corporation Stock DeferralPlan or the Constellation Energy Group Inc. Deferred Compensation Plan, any successor plan, or under any other non-qualifieddefined contribution or deferred compensation plan of the Company, whether vested or non-vested, together with any accruedearnings thereon, to the extent that such amounts and earnings have not been previously paid by the Company and are notprovided under the terms of any such non-qualified plan; (iii)SERP Enhancement. An amount payable under the SERP equal to the positive difference, if any, between: (1)the lump sum value of such Participant’s benefit, if any, under the SERP, calculated as if such Participant had: (a)become fully vested in all Pension Plan and SERP benefits, (b)to the extent age is relevant under the Pension Plan covering the Participant, attained as of the Termination Date anage that is two years greater than such Participant’s actual age and that includes the number of years of age creditedto such Participant pursuant to any other agreement between the Company and such Participant, (c)to the extent service is relevant under the Pension Plan covering the Participant, accrued a number of years of service(for purposes of determining the amount of such benefits, entitlement to - but not commencement of - earlyretirement benefits, and all other purposes of the Pension Plan and SERP) that is two years greater than the number ofyears of service actually accrued by such Participant as of the Termination Date and that includes the number ofyears of service credited to such Participant pursuant to any other agreement between the Company and suchParticipant, and (d)received the severance benefits specified in Sections 5.1(a)(i) and 5.1(a)(v) as covered compensation in regularinstallments during the Severance Period, minus (2)the aggregate amounts paid or payable to such Participant under the SERP; 7Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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)Non-vested Benefits Under Pension Plan. An amount equal to the actuarial equivalent present value of any non-vested portion ofsuch Participant’s accrued benefit under the Pension Plan as of the Termination Date and forfeited by such Participant by reason ofthe Termination of Employment; and (v)Multiple of Salary and Severance Incentive. An amount equal to two (2) times the sum of (x) the Participant’s Base Salary plus, ifthe Participant is a participant in the Annual Incentive Award Plan for the year in which the Termination Date occurs, (y) theSeverance Incentive, net of applicable taxes and other deductions. (b)Stock Options. Each of such Participant’s stock options granted under the LTIP (“Stock Options”) shall (i) become fully vested, and (ii)remain exercisable until the fifth anniversary of the Termination Date or, if earlier, the expiration date of any such Stock Option,provided that this Section 5.1(b) shall not limit the right of the Company to cancel the Stock Options in connection with a corporatetransaction pursuant to the terms of the LTIP. (c)Performance Share Vesting. On the Termination Date, all of the long term performance share or performance cash units granted to suchParticipant under the LTIP (“Performance Shares”) prior to January 1, 2013 to the extent earned by and awarded to such Participant (i.e.as to which the applicable performance cycle has elapsed) as of the Termination Date, shall become fully vested at the actual level earnedand awarded, and, to the extent not yet earned by and awarded to such Participant (i.e. as to which the current performance cycle has notelapsed) as of the Termination Date, shall become fully vested at the earned level determined as of the last day of the applicableperformance cycle. With respect to all Performance Shares granted on or after January 1, 2013, such Performance Shares shall becomevested and earned as set forth in the LTIP, as if the Executive had been involuntarily terminated without cause. (d)Other Awards. All forfeiture conditions that as of the Termination Date are applicable to any shares of restricted stock or restricted stockunits awarded to such Participant by Exelon other than under the Exelon Long Term Performance Share Award Program under the LTIP(“Restricted Stock”) shall (except as expressly provided to the contrary in the applicable awards) lapse immediately and all such awardswill become fully vested. All Cash Performance Awards shall become fully vested in accordance with their terms. (e)Continuation of Welfare Benefits. During the Severance Period, the Executive and the Executive’s dependents shall be eligible forparticipation in the Company’s welfare plans, including medical, prescription, dental, disability, employee life, group life and accidentaldeath benefits but excluding any severance pay (“Welfare Plans”) that 8Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. covered the Participant or such Participant’s dependents as of the Termination Date, in accordance with the terms and conditions of suchplans and applicable law. Such provision of welfare benefits shall be subject to the following: (i)In determining benefits applicable under such Welfare Plans, such Participant’s annual compensation attributable to base salaryand incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than such Participant’s Base Salaryand annual incentive for the year in which the Termination Date occurs. (ii)The cost of such welfare benefits to such Participant and dependents under this Section 5.1(e) shall not exceed the cost of suchbenefits to peer executives who are actively employed during the Severance Period. (iii)Health care coverage under this Section 5.1(e) shall be provided for the duration of the Severance Period in lieu of continuationcoverage under Section 4980B of the Code and Section 601 to 609 of ERISA (“COBRA”) for the same period. At the end of theSeverance Period, COBRA continuation coverage may be elected for the remaining balance of the statutory coverage period, ifany, at the Participant’s sole expense. (iv)If such Participant has, as of the last day of the Severance Period, attained age 50 and completed at least 10 years of service withthe Company, such Participant shall be entitled to elect coverage under such Company group health care programs for retirees asare in effect as of the Termination Date and are applicable to such Participant by the programs’ eligibility terms and conditions asthough such Participant had attained such programs’ age and service requirements ; provided, however, that for purposes hereof,any years of age and/or credited service granted to such Participant in any other plan or agreement between such Participant andthe Company shall be taken into account. For purposes of determining eligibility for (but not the time of commencement of) suchretiree benefits, such Participant shall also be considered (1) to have remained employed until the last day of the Severance Periodand to have retired on the last day of such period, and (2) to have attained at least the age such Participant would have attained onthe last day of the Severance Period. The eligibility for coverage and availability of programs or plans, the amounts charged forcoverage, and the other terms, conditions and limitations under the Company’s group health care programs or plans shall remainsubject to the Company’s right to amend, change or terminate such programs or plans at any time. 9Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Notwithstanding the foregoing, if such Participant is eligible to obtain a specific type of coverage under welfare plan(s) sponsoredby another employer of such Participant (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits,group life insurance benefits, but excluding for the purposes of this sentence retiree benefits if such Participant is so eligible), thenthe Company shall not be obligated to provide any such specific type of coverage. The Participant shall promptly notify the PlanAdministrator of any such coverage. (f)Outplacement. To the extent actually incurred by such Participant, the Company shall pay or cause to be paid on behalf of suchParticipant, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by suchParticipant for outplacement services provided for up to 12 months after the Termination Date. No cash shall be paid in lieu of suchfees and costs. (g)Indemnification. Such Participant shall be indemnified and held harmless by the Company to the greatest extent permitted underapplicable law and the Company’s by-laws if such Participant was, is, or is threatened to be, made a party to any pending, completedor threatened action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any otherproceeding brought by a third party (and not by or on behalf of the Company or its shareholders) whether civil, criminal,administrative or investigative, and whether formal or informal, by reason of the fact that such Participant is or was, or had agreed tobecome, a director, officer, employee, agent, or fiduciary of the Company or any other entity which such Participant is or wasserving at the request of the Company (“Proceeding”), against all expenses (including all reasonable attorneys’ fees) and all claims,damages, liabilities and losses incurred or suffered by such Participant or to which such Participant may become subject for anyreason; provided, that the Participant provides the Company written notice of any such Proceeding promptly after receipt and suchthat the Company’s ability to defend shall not be prejudiced in any fashion and the Company shall have the right to direct thedefense, approve any settlement and shall not be required to indemnify the Participant in connection with any proceeding initiatedby the Participant, including a counterclaim or crossclaim, unless such proceeding was authorized by the Company, and that theParticipant fully cooperates in the investigation and defense of such Proceeding. (h)Directors’ and Officers’ Liability Insurance. For a period of six years after the Termination Date, the Company shall provide suchParticipant with coverage under a directors’ and officers’ liability insurance policy in an amount no less than, and on terms no lessfavorable than, those provided to peer executives of the Company from time to time. 5.2.Termination During an Imminent Control Change Period. If, during an Imminent Control Change Period, a Participant has a Termination ofEmployment, then 10Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. such Participant shall receive benefits at the time and in the manner provided in Section 4 and the Company’s sole obligations to suchParticipant under Sections 5.1 and 5.2 shall be as set forth in this Section 5.2 (and subject to Sections 5.3, 5.5, 5.6 and 6). The Company’sobligations to such Participant under this Section 5.2 shall in all events be reduced by any amounts or benefits paid or provided pursuant toSection 4. (a)Cash Severance Payments. If the Imminent Control Change Period culminates in a Change Date, the Company shall pay (or cause tobe paid) to such Participant the amounts described in Section 5.1(a)(i) through (v). Such amounts shall be paid to such Participant asdescribed in Section 5.3, provided that amounts that would have been paid prior to the Change Date shall be paid in a lump sum(without interest) within 30 business days after the Change Date. (b)Vested Stock Options. Such Participant’s Stock Options, to the extent vested on the Termination Date, (i)will not expire (unless such Stock Options would have expired had such Participant remained an employee of the Company)during the Imminent Control Change Period; and (ii)will continue to be exercisable after the Termination Date to the extent provided in the applicable grant agreement or theLTIP, and thereafter such Stock Options shall not be exercisable during the Imminent Control Change Period.If the Imminent Control Change Period lapses without a Change Date, then such Participant’s Stock Options, to the extent vested onthe Termination Date, may be exercised, in whole or in part, during the 30-day period following the lapse of the Imminent ControlChange Period, or, if longer, the period during which such Participant’s vested Stock Options could otherwise be exercised underthe terms of the applicable grant agreement or the LTIP (but in no case shall any Stock Options remain exercisable after the date onwhich such Stock Options would have expired if such Participant had remained an employee of the Company).If the Imminent Control Change Period culminates in a Change Date, then effective upon the Change Date, such Participant’s StockOptions, to the extent vested on the Termination Date, may be exercised in whole or in part by such Participant at any time until theearlier of the fifth anniversary of the Change Date or the option expiration date for such Stock Options, provided that this Section5.2(b) shall not limit the right of the Company to cancel the Stock Options in connection with a corporate transaction pursuant tothe terms of the LTIP. 11Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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)Non-vested Stock Options. Such Participant’s Stock Options that are not vested on the Termination Date: (i)will not expire (unless such Stock Options would have expired had such Participant remained an employee of the Company)during the Imminent Control Change Period; and (ii)will not continue to vest and will not be exercisable during the Imminent Control Change Period.If the Imminent Control Change lapses without a Change Date, such non-vested Stock Options will thereupon expire.If the Imminent Control Change culminates in a Change Date, then immediately prior to the Change Date, such non-vested StockOptions shall become fully vested, and may thereupon be exercised in whole or in part by such Participant at any time until theearlier of the fifth anniversary of the Change Date, or the option expiration date for such Stock Options, provided that this Section5.2(c) shall not limit the right of the Company to cancel the Stock Options in connection with a corporate transaction pursuant tothe terms of the LTIP. (d)Performance Shares. Such Participant’s Performance Shares granted under the Exelon Long Term Performance Share Award Programunder the LTIP will not be forfeited during the Imminent Control Change Period, and will not continue to vest during the ImminentControl Change Period. If the Imminent Control Change lapses without a Change Date, such Performance Shares shall be governedaccording to the terms of Section 4. If the Imminent Control Change Period culminates in a Change Date: (i)All Performance Shares granted to such Participant under the Exelon Long Term Performance Share Award Program underthe LTIP prior to January 1, 2013, which, as of the Termination Date, have been earned by and awarded to such Participant,shall become fully vested at the actual earned level on the Change Date, and (ii)All of the Performance Shares granted to such Participant under the Exelon Long Term Performance Share Award Programunder the LTIP prior to January 1, 2013 which, as of the Termination Date, have not been earned by and awarded to suchParticipant shall become fully vested on the Change Date at the actual earned level as of the last day of the applicableperformance cycle, and (iii)With respect to all Performance Shares granted on or after January 1, 2013, such Performance Shares shall become vested andearned as set forth in the LTIP, as if the Executive had been involuntarily terminated without cause. (e)Restricted Stock. Such Participant’s non-vested Restricted Stock will: (i)not be forfeited during the Imminent Control Change Period; and (ii)not continue to vest during the Imminent Control Change Period. 12Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.If the Imminent Control Change Period lapses without a Change Date, such non-vested Restricted Stock shall thereupon beforfeited.If the Imminent Control Change Period culminates in a Change Date, then immediately prior to the Change Date, such Participant’sRestricted Stock shall (except as expressly provided to the contrary in the award) become fully vested, and within ten business daysafter the Change Date, the Company shall deliver to such Participant all of such shares theretofore held by or on behalf of theCompany, which will be subject to the same terms which other stockholders of the Company receive in the transaction. (f)Cash Performance Awards. All Cash Performance Awards shall become fully vested in accordance with the terms of the underlyingaward documents. (g)Continuation of Welfare Benefits. The Participant and the Participant’s dependents shall be eligible for welfare benefits (other thanany severance pay that may be considered a welfare benefit) in accordance with the terms and conditions of the applicable plansduring the Imminent Control Change Period, to the same extent as if such Participant had remained employed during such period,subject to the following: (i)in determining benefits applicable under such Welfare Plans, such Participant’s annual compensation attributable to basesalary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than such Participant’sBase Salary and annual incentive for the year in which the Termination Date occurs; (ii)the cost of such welfare benefits to such Participant and dependents under this Section 5.2(g) shall not exceed the cost ofsuch benefits to peer executives who are actively employed by the Company during the Imminent Control Change Period;and (iii)Health care coverage under this Section 5.2(g) shall be provided for the duration of the Severance Period in lieu ofcontinuation coverage under Section 4980B of the Code and Section 601 to 609 of ERISA (“COBRA”) for the same period.At the end of the Severance Period, COBRA continuation coverage may be elected for the remaining balance of the statutorycoverage period, if any.If the Imminent Control Change Period lapses without a Change Date, welfare benefit plan coverage under this Section 5.2(g) shallthereupon cease, subject to such Participant’s rights, if any, to continued coverage under a Welfare Plan, Section 4, or applicablelaw. If the Imminent Control Change Period culminates in a Change Date, then for the remainder of the Severance Period, theParticipant and his or her dependents shall continue to be eligible for welfare benefits as described in, and subject to the limitationsof Section 5.1(e). 13Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Notwithstanding the foregoing, if such Participant obtains a specific type of coverage under welfare plan(s) sponsored by anotheremployer of such Participant (e.g. medical, prescription, vision, dental, disability, individual life insurance benefits, group lifeinsurance benefits, but excluding for the purposes of this sentence retiree benefits if such Participant is so eligible), then theCompany shall not be obligated to provide any such specific type of coverage. The Participant shall immediately notify the PlanAdministrator of any such coverage. (h)Indemnification. Such Participant shall be indemnified and held harmless by the Company to the same extent as provided in Section5.1(g), but only during the Imminent Control Change Period (or greater period provided under the Company’s by-laws) if theImminent Control Change Period lapses without a Change Date. (i)Termination During an Imminent Control Change Period: Directors’ and Officers’ Liability Insurance. The Company shall providethe same level of directors’ and officers’ liability insurance for such Participant as provided in Section 5.1(h), but only during theImminent Control Change Period (or greater period provided under the Company’s by-laws) if the Imminent Control Change Periodlapses without a Change Date. 5.3.Timing of Severance Payments. Unless otherwise specified herein, the Accrued Obligations and the amount described in Section 5.1(a)(i) shallbe paid within 30 business days of the Termination Date, and such amounts shall be considered “short-term deferrals” within the meaning ofSection 409A of the Code. The amounts described in Sections 5.1(a)(ii), (iii) and (iv) shall be paid in accordance with the applicable deferredcompensation plan or the SERP and the Participant’s distribution election thereunder as of the Termination Date (or, if no affirmative electionis in effect as of such date, the default election in effect with respect to the Participant as of such date). Subject to Section 13.13, the severancepayments described in Section 5.1(a)(v) shall be paid during the Severance Period, beginning no later than the second paydate which occursafter the Termination Date, in periodic payments to a Participant according to the Company’s normal payroll practices at a monthly rate equalto 1/12 of the sum of (i) such Participant’s Base Salary plus (ii) the Severance Incentive (if any). The in-kind benefits and reimbursementsprovided under each of Sections 5.1(e), 5.1(h), 5.2(g) and 5.2(i) during any calendar year shall not affect the benefits or reimbursements to beprovided under such section in any subsequent calendar year. The right to such benefits and reimbursements shall not be subject toliquidation or exchange for any other benefit. 14Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. 5.4.Other Terminations of Employment by the Company or a Participant. (a)Obligations. If, during a Post-Change Period or an Imminent Control Change Period, (i) the Company terminates an eligibleExecutive’s employment for Cause (or causes a Participant to be terminated for Cause) (“Cause Termination”) or disability (asdetermined by the Plan Administrator in good faith), (ii) an Executive elects to retire or otherwise terminate employment other thanfor Good Reason, disability or death, or (iii) an eligible Executive’s employment terminates on account of death, the Company shallhave no obligations to such Executive under Section 5. The remaining applicable provisions of this Plan (including the RestrictiveCovenants) shall continue to apply. (b)Procedural Requirements. The Company shall strictly observe or cause to be strictly observed each of the following procedures inconnection with any Cause Termination during a Post-Change Period or an Imminent Control Change Period: an eligibleExecutive’s termination of employment shall not be deemed to be for Cause under this Section 5.4 unless and until there shall havebeen delivered to such Executive a written notice of the determination of the Chief Executive Officer of the Executive’s employer(“CEO”) (after reasonable written notice of such consideration by the CEO of acts or omissions alleged to constitute Cause isprovided to such Executive and such Executive is given an opportunity to present a written response to the CEO regarding suchallegations), finding that, in his or her good faith opinion, such Executive’s acts, or failure to act, constitutes Cause and specifyingthe particulars thereof in detail. 5.5.Sole and Exclusive Obligations. The obligations of the Company under this Plan with respect to any Termination of Employment occurringduring a Post-Change Period or Imminent Control Change Period shall supersede any severance obligations of the Company in any other planof the Company or agreement between such Participant and the Company, including, without limitation, Section 4, any offer of employmentor employment contract of the Company which provides for severance benefits, except as explicitly provided in Section 5.2 or to the extentsuch Participant is ineligible for such benefits or such benefits are waived pursuant to Section 2.1. 5.6.Payment Capped. If at any time or from time to time, it shall be determined by the Company’s independent auditors that any payment or otherbenefit to a Participant pursuant to Section 4 or 5 of this Plan or otherwise (“Potential Parachute Payment”) is or will become subject to theexcise tax imposed by Section 4999 of the Code or any similar tax payable under any United States federal, state, local, foreign or other law(“Excise Taxes”), then the Potential Parachute Payments payable to such Participant shall be reduced to the largest amount which would both(a) not cause any Excise Tax to be payable by such Participant and (b) not cause any Potential Parachute Payments to become nondeductibleby the Company by reason of Section 280G of the Code (or any successor provision). 15Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.6.TERMINATION OF PARTICIPATION; CESSATION OF BENEFITSA Participant’s benefits under Section 4 of the Plan shall terminate on the last day of the Participant’s Salary Continuation Period; provided that aParticipant’s right to benefits shall terminate immediately on such date as the Company discovers that the Participant has breached any of the RestrictiveCovenants or the Waiver and Release, or if at any time the Company determines that in the course of his or her employment the Executive engaged inconduct described in Section 7.11(b), (c), (d) or (e) or the Executive fails to comply with Section 13.2, in which case the Company may require the repaymentof amounts paid pursuant to Section 4.1 prior to such breach or other conduct, and shall discontinue the payment of any additional amounts under Section 4of the Plan.A Participant’s benefits under Section 5 of the Plan shall terminate on the later of the last day of the Participant’s Severance Period or the date allbenefits to which the Participant is entitled to have been paid from the Plan; provided that a Participant’s right to benefits shall terminate immediately on thedate the Company discovers that the Participant has breached any of the Restrictive Covenants or the Waiver and Release, or if at any time the Companydetermines, in accordance with the procedural requirements set forth in Section 5.4(b) that in the course of his or her employment the Executive engaged inconduct described in Section 7.11(b), (c), (d) or (e) or the Executive fails to comply with Section 13.2, in which case the Company may require the repaymentof amounts paid pursuant to Section 5 prior to such breach or other conduct, and shall discontinue the payment of any additional amounts under Section 5 ofthe Plan.Benefits paid or payable to a Participant under Section 4 and Section 5 of the Plan shall be subject to any executive or officer incentive compensationrecoupment policy of the Board of Directors as in effect as of the Termination Date. 7.DEFINITIONSIn addition to terms previously defined, when used in the Plan, the following capitalized terms shall have the following meanings unless the contextclearly indicates otherwise: 7.1.“Accrued Annual Incentive” means the amount of any annual incentive earned but not yet paid with respect to the Company’s latest fiscalyear ended prior to the Termination Date. 7.2.“Accrued Base Salary” means the amount of a Participant’s Base Salary that is accrued but not yet paid as of the Termination Date. 7.3.“Accrued Obligations” means, as of any date, the sum of a Participant’s Accrued Base Salary, Accrued Annual Incentive and any accrued butunpaid paid time off 7.4.“Annual Incentive” as of a certain date means an amount to which a Participant would have been entitled under the Annual Incentive AwardPlan (or, with respect to a termination pursuant to Section 5, such other Incentive Plan applicable to such Participant) for the applicableperformance period based on the actual achievement performance goals established pursuant to such plan as of the end of the applicableperformance period had the Participant remained employed through 16Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 last day of such period; provided, however, that any reduction in a Participant’s Base Salary or annual incentive that would qualify asGood Reason shall be disregarded for purposes of this definition 7.5.“Annual Incentive Award Plan”, means the Exelon Corporation Annual Incentive Award Plan (but not any other short-term incentive plan of aCompany), or any successor plan thereto (including but not limited to any annual incentive plan of a successor to Exelon pursuant to aChange in Control). 7.6.“Applicable Trigger Date” means (a)the Change Date, with respect to a Post-Change Period; or (b)the date of an Imminent Control Change, with respect to the Imminent Control Change Period. 7.7.“Base Salary” for purposes of Section 5, means not less than 12 times the highest monthly base salary paid or payable to a Participant by theCompany in respect of the 12-month period immediately before the Applicable Trigger Date. 7.8.“Beneficial Owner” means such term as defined in Rule 13d-3 of the SEC under the Exchange Act. 7.9.“Board” means the Board of Directors of Exelon or, from and after the effective date of a Corporate Transaction (as defined in the definition ofChange in Control), the Board of Directors of the corporation resulting from a Corporate Transaction or, if securities representing at least 50%of the aggregate voting power of such resulting corporation are directly or indirectly owned by another corporation, such other corporation. 7.10.“Cash Performance Award” means any cash performance award granted to a Participant in lieu of an award of Performance Shares or RestrictedStock under the LTIP. 7.11.“Cause” means, with respect to any Executive: (a)the refusal to perform or habitual neglect in the performance of the Executive’s duties or responsibilities, or of specific directives ofthe officer or other executive of Exelon or any of its affiliates to whom the Executive reports which are not materially inconsistentwith the scope and nature of the Executive’s employment duties and responsibilities; (b)an Executive’s willful or reckless commission of act(s) or omission(s) which have resulted in or are likely to result in, a material lossto, or material damage to the reputation of, Exelon or any of its affiliates, or that compromise the safety of any employee or otherperson; (c)the Executive’s commission of a felony or any crime involving dishonesty or moral turpitude; 17Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. (d)an Executive’s material violation of Exelon’s or any of its affiliate’s Code of Business Conduct (including the corporate policiesreferenced therein), or of any statutory or common law duty of loyalty to Exelon or any of its affiliates; or (e)any breach by the Executive of any one or more of the Restrictive Covenants. 7.12.“Change Date” means each date on which a Change in Control occurs after the Effective Date. 7.13.“Change in Control” means: (a)any SEC Person becomes the Beneficial Owner of 20% or more of the then outstanding common stock of Exelon or of VotingSecurities representing 20% or more of the combined voting power of all the then outstanding Voting Securities of Exelon (such anSEC Person, a “20% Owner”); provided, however, that for purposes of this subsection (a), the following acquisitions shall notconstitute a Change in Control: (1) any acquisition directly from Exelon (excluding any acquisition resulting from the exercise ofan exercise, conversion or exchange privilege unless the security being so exercised, converted or exchanged was acquired directlyfrom Exelon), (2) any acquisition by Exelon, (3) any acquisition by an employee benefit plan (or related trust) sponsored ormaintained by Exelon or any corporation controlled by Exelon (a “Company Plan”), or (4) any acquisition by any corporationpursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this definition; provided further, that forpurposes of clause (2), if any 20% Owner of Exelon other than Exelon or any Company Plan becomes a 20% Owner by reason of anacquisition by Exelon, and such 20% Owner of Exelon shall, after such acquisition by Exelon, become the beneficial owner of anyadditional outstanding common shares of Exelon or any additional outstanding Voting Securities of Exelon (other than pursuant toany dividend reinvestment plan or arrangement maintained by Exelon) and such beneficial ownership is publicly announced, suchadditional beneficial ownership shall constitute a Change in Control; or (b)Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least amajority of the Incumbent Board; provided, however, that any individual becoming a director subsequent to the date hereof whoseelection, or nomination for election by Exelon’s shareholders, was approved by a vote of at least a majority of the directors thencomprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, butexcluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatenedelection contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) or other actual or threatenedsolicitation of proxies or consents by or on behalf of a Person other than the Board; or 18Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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)Consummation of a reorganization, merger or consolidation (“Merger”), or the sale or other disposition of more than 50% of theoperating assets of Exelon (determined on a consolidated basis), other than in connection with a sale-leaseback or other arrangementresulting in the continued utilization of such assets (or the operating products of such assets) by Exelon (such reorganization,merger, consolidation, sale or other disposition, a “Corporate Transaction”); excluding, however, a Corporate Transaction pursuantto which: (i)all or substantially all of the individuals and entities who are the Beneficial Owners, respectively, of the outstandingcommon stock of Exelon and outstanding Voting Securities of Exelon immediately prior to such Corporate Transactionbeneficially own, directly or indirectly, more than 60% of, respectively, the then-outstanding shares of common stock andthe combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors,as the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, acorporation which, as a result of such transaction, owns Exelon or all or substantially all of the assets of Exelon eitherdirectly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior tosuch Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities of Exelon, asthe case may be; (ii)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 commonstock of Exelon or the outstanding Voting Securities of Exelon, as the case may be) becomes a 20% Owner, directly orindirectly, of the then-outstanding common stock of the corporation resulting from such Corporate Transaction or thecombined voting power of the outstanding voting securities of such corporation; and (iii)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 (d)Approval by Exelon’s shareholders of a plan of complete liquidation or dissolution of Exelon, other than a plan of liquidation ordissolution which results in the acquisition of all or substantially all of the assets of Exelon by an affiliated company. 19Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Notwithstanding the occurrence of any of the foregoing events, a Change in Control shall not occur with respect to a Participant if, inadvance of such event, such Participant agrees in writing that such event shall not constitute a Change in Control. 7.14.“Code” means the Internal Revenue Code of 1986, as amended. 7.15.“ComEd Key Manager Plan” means the ComEd Key Manager Long-Term Performance Plan, or any successor thereto. 7.16.“ERISA” means the Employee Retirement Income Security Act of 1974, as amended. 7.17.“Exchange Act” means the Securities Exchange Act of 1934, as amended. 7.18.“Good Reason” means: (a)for purposes of Section 4 hereof, (i)a material reduction of an Executive’s salary unless such reduction is part of a policy, program or arrangement applicable topeer executives of the Company or of the Executive’s business unit; and (ii)with respect to an Executive whose title with respect to a Company is Senior Vice President or above, a material adversereduction in the Executive’s position or duties that is not applicable to peer executives of the Company or of theExecutive’s business unit, but excluding any change (A) resulting from a reorganization or realignment of all or a significantportion of the business, operations or senior management of the Company or of the business unit that employs the Executiveor (B) that generally places the Executive in substantially the same level of responsibility. Notwithstanding the foregoing,no change in the position or level of officer to whom an Executive reports shall constitute grounds for Good Reason. (b)for purposes of Section 5 hereof, the occurrence of any one or more of the following actions or omissions that occurs during a Post-Change Period or an Imminent Control Change Period: (i)a material reduction of an Executive’s salary, incentive compensation opportunity or aggregate benefits unless suchreduction is part of a policy, program or arrangement applicable to peer executives (including peer executives of anysuccessor to Exelon); (ii)a material adverse reduction in the Executive’s position, duties or responsibilities (excluding a change in the position orlevel of officer to whom the Executive reports), unless such reduction is part of a policy, program or arrangement applicableto peer executives (including peer executives of any successor to Exelon); 20Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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)a relocation by more than 50 miles of (A) the Executive’s primary workplace, or (B) the principal offices of Exelon or itssuccessor (if such offices are such Executive’s workplace), in each case without the Executive’s consent; provided, however,in both cases of (A) and (B) of this subsection (b)(iv), such new location is farther from the Executive’s residence than theprior location; or (iv)a material breach of this Plan by Exelon or its successor. (c)Application of “Good Reason” Definition During the Imminent Control Change Period. During the Imminent Control ChangePeriod, “Good Reason” shall not include the events or conditions described in subsection (b)(i), (b)(ii) or (b)(iv) above unless theImminent Control Change Period culminates in a Change Date. (d)Limitations on Good Reason. Notwithstanding the foregoing provisions of this Section, no act or omission shall constitute amaterial breach of this Plan by Exelon, nor grounds for “Good Reason”: (i)unless the Executive gives the Plan Administrator a Notice of Termination at least 30 days prior to the Executive’sTermination Date, and the Company fails to cure such act or omission within the 30-day period; (ii)if the Executive first acquired knowledge of such act or omission more than 90 days before such Participant gives the PlanAdministrator such Notice or Termination; or (iii)if the Executive has consented in writing to such act or omission. 7.19.“Imminent Control Change” means, as of any date on or after the Effective Date and prior to the Change Date, the occurrence of any one ormore of the following: (a)Exelon enters into an agreement the consummation of which would constitute a Change in Control; (b)Any SEC Person commences a “tender offer” (as such term is used in Section 14(d) of the Exchange Act) or exchange offer, which, ifconsummated, would result in a Change in Control; or (c)Any SEC Person files with the SEC a preliminary or definitive proxy solicitation or election contest to elect or remove one or moremembers of the Board, which, if consummated or effected, would result in a Change in Control; 21Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.provided, however, that an Imminent Control Change will lapse and cease to qualify as an Imminent Control Change: (i)With respect to an Imminent Control Change described in clause (a) of this definition, the date such agreement is terminated,cancelled or expires without a Change Date occurring; (ii)With respect to an Imminent Control Change described in clause (b) of this definition, the date such tender offer or exchangeoffer is withdrawn or terminates without a Change Date occurring; (iii)With respect to an Imminent Control Change described in clause (c) of this definition, (1) the date the validity of such proxysolicitation or election contest expires under relevant state corporate law, or (2) the date such proxy solicitation or electioncontest culminates in a shareholder vote, in either case without a Change Date occurring; or (iv)The date a majority of the members of the Incumbent Board make a good faith determination that any event or conditiondescribed in clause (a), (b), or (c) of this definition no longer constitutes an Imminent Control Change, provided that suchdetermination may not be made prior to the first anniversary of the occurrence of such event. 7.20.“Imminent Control Change Period” means the period commencing on the date of an Imminent Control Change, and ending on the first tooccur thereafter of (a)a Change Date, provided (i)such date occurs no later than the first anniversary of the Termination Date, and (ii)either the Imminent Control Change has not lapsed, or the Imminent Control Change in effect upon such Change Date is thelast Imminent Control Change in a series of Imminent Control Changes unbroken by any period of time between the lapse ofan Imminent Control Change and the occurrence of a new Imminent Control Change; (b)the date an Imminent Control Changes lapses without the prior or concurrent occurrence of a new Imminent Control Change; or (c)the first anniversary of the Termination Date. 7.21.“Incentive Plan” means the Exelon Corporation Annual Incentive Award Plan, or such other annual cash bonus arrangement of the Companyin which the Executive is a participant in lieu of the Annual Incentive Award Plan, but excluding any supplemental incentive plans. 22Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. 7.22.“including” means including without limitation. 7.23.“Incumbent Board” - see definition of Change in Control. 7.24.“LTIP” means the Exelon Corporation Long-Term Incentive Plan, as amended from time to time, or any successor thereto. 7.25.“LTIP Performance Period” means the performance period applicable to an LTIP award, as designated in accordance with the LTIP. 7.26.“LTIP Target Level” means, in respect of any grant of Performance Shares under the Exelon Long Term Performance Share Award Programunder the LTIP, the number of Performance Shares which a Participant would have been awarded (prior to the Termination Date) for the LTIPPerformance Period corresponding to such grant if the business and personal performance goals related to such grant were achieved at the100% (target) level as of the end of the LTIP Performance Period. 7.27.“Merger” - see definition of Change in Control. 7.28.“Notice of Termination” means a written notice given by an Executive in accordance with Sections 7.18(d)(i) and 13.10 which sets forth inreasonable detail the specific facts and circumstances claimed to provide a basis for a Termination of Employment for Good Reason. 7.29.“Performance Shares” - see Section 5.1(c). 7.30.“Person” means 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. 7.31.“Plan Administrator” – See Section 9. 7.32.“Post-Change Period” means the period commencing on a Change Date and ending on the earlier of (a) the Termination Date or (b) the secondanniversary of such Change Date; provided that no duplicate benefits shall be paid with respect to simultaneous or overlapping Post-ChangePeriods. 7.33.“Restricted Stock” — see Section 5.1(d). 7.34.“Retiree” means a Participant who, as of his or her Termination Date, is eligible for “retirement” as defined in the LTIP. 7.35.“Salary Continuation Period” means the applicable period designated in Section 4.1 during which severance is payable. 7.36.“SEC” means the United States Securities and Exchange Commission. 23Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. 7.37.“SEC Person” means any person (as such term is used in Rule 13d-5 of the SEC under the Exchange Act) or group (as such term is defined inSections 3(a)(9) and 13(d)(3) of the Exchange Act), other than (a) Exelon or any Person that directly or indirectly controls, is controlled by, oris under common control with, Exelon (an “Affiliate”). For purposes of this definition the term “control” with respect to any Person means thepower to direct or cause the direction of management or policies of such Person, directly or indirectly, whether through the ownership ofVoting Securities, by contract or otherwise, or (b) any employee benefit plan (or any related trust) of Exelon or any of its Affiliates. 7.38.“Section” means, unless the context otherwise requires, a section of this Plan. 7.39.“Senior Executive Management” means (a) an Executive whose title with respect to Exelon is Executive Vice President or above, (b) anExecutive whose title is President or Chief Executive Officer with respect to Baltimore Gas & Electric Company, Commonwealth EdisonCompany, Exelon Generation Company, LLC, PECO Energy Company or such other Company as may be designated by Exelon’s ChiefHuman Resources Officer, and (c) such other Executive who was described in subparagraph (a) or (b) and has been grandfathered by the PlanAdministrator. 7.40.“SERP” means the Constellation Energy Group, Inc. Benefit Restoration Plan, the PECO Energy Company Supplemental Retirement Plan orthe Exelon Corporation Supplemental Executive Retirement Plan, whichever is applicable to a Participant, or any successor thereto. 7.41.“Severance Incentive” means the Target Incentive for the performance period in which the Termination Date occurs; provided, however, thatfor purposes of Section 5, “Severance Incentive” shall mean the greater of (a) the Target Incentive for the performance period in which theTermination Date occurs, or (b) the average of the actual Annual Incentives paid (or payable, to the extent not previously paid) to aParticipant under the Annual Incentive Award Plan for each of the two calendar years preceding the calendar year in which the TerminationDate occurs. 7.42.“Severance Period” means the period beginning on a Participant’s Termination Date, provided such Participant’s Termination of Employmententitles such Participant to benefits under Section 5.1 or 5.2, and ending on the second anniversary thereof. 7.43.“Specified Employee” means a “specified employee” within the meaning of Section 409A of the Code. 7.44.“Stock Options” — see Section 5.1(b). 7.45.“Target Incentive” as of a certain date means an amount equal to the product of Base Salary determined as of such date multiplied by thepercentage of such Base Salary (if any) to which a Participant would have been entitled immediately prior to such date under the AnnualIncentive Award Plan for the applicable 24Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 period if the performance goals established pursuant to such plan were achieved at the 100% (target) level as of the end of theapplicable performance period; provided, however, that any reduction in a Participant’s Base Salary or annual incentive that would qualify asGood Reason shall be disregarded for purposes of this definition. 7.46.“Taxes” means the incremental federal, state, local and foreign income, employment, excise and other taxes payable by a Participant withrespect to any applicable item of income. 7.47.“Termination Date” means the effective date of an eligible Executive’s Termination of Employment with the Company for any or no reason,which shall be the date on which such Executive has a “separation from service,” within the meaning of Section 409A of the Code; provided,however, that if the Executive terminates his or her employment for Good Reason, the Termination Date shall not be earlier than the thirtiethday following the Company’s receipt of such Executive’s Notice of Termination, unless the Exelon consents in writing to an earlierTermination Date. 7.48.“Termination of Employment” means: (a)a termination of an eligible Executive’s employment by the Company for reasons other than for Cause; or (b)a resignation by an eligible Executive for Good Reason.The following shall not constitute a Termination of Employment for purposes of the Plan: (i) a termination of employment for Cause, (ii) anExecutive’s resignation for any reason other than for Good Reason, (iii) the cessation of an Executive’s employment with the Company or anyAffiliate due to death or disability (as determined by the Plan Administrator in good faith), or (iv) the cessation of an Executive’s employment withthe Company or any subsidiary thereof as the result of the sale, spin-off or other divestiture of a plant, division, business unit or subsidiary or a mergeror other business combination followed by employment or reemployment with the purchaser or successor in interest to the Executive’s employer withregard to such plant, division, business unit or subsidiary, or an offer of employment by such purchaser or successor in interest on terms andconditions comparable in the aggregate (as determined by the Plan Administrator in its sole discretion) to the terms and conditions of the Executive’semployment with the Company or its subsidiary immediately prior to such transaction. 7.49.“20% Owner” — see paragraph (a) of the definition of “Change in Control.” 7.50.“Voting Securities” means with respect to a corporation, securities of such corporation that are entitled to vote generally in the election ofdirectors of such corporation. 25Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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.FUNDINGThe Plan is an unfunded employee welfare benefit plan maintained for the purpose of providing severance benefits to a select group of management orhighly compensated employees. Nothing in the Plan shall be interpreted as requiring the Company to set aside any of its assets for the purpose of funding itsobligations under the Plan. No person entitled to benefits under the Plan shall have any right, title or claim in or to any specific assets of the Company, butshall have the right only as a general creditor to receive benefits from the Company on the terms and conditions provided in the Plan. 9.ADMINISTRATION OF THE PLANThe Plan shall be administered on a day-to-day basis by the Vice President, Corporate Compensation of Exelon (the “Plan Administrator”). The PlanAdministrator has the sole and absolute power and authority to interpret and apply the provisions of this Plan to a particular circumstance, make all factualand legal determinations, construe uncertain or disputed terms and make eligibility and benefit determinations in such manner and to such extent as the PlanAdministrator, in his or her sole discretion may determine. Benefits under the Plan will be paid only if the Plan Administrator, in his or her discretion,determines that an individual is entitled to them; provided, however, that any dispute after the claims procedure under Section 10 has been exhaustedregarding whether an Executive’s termination of employment for purposes of Section 5 is based on either Good Reason or Cause may, at the election of theExecutive, be submitted to binding arbitration pursuant to Section 11.The Plan Administrator may promulgate any rules and regulations it deems necessary to carry out the purposes of the Plan or to interpret the terms andconditions of the Plan; provided, however, that no rule, regulation or interpretation shall be contrary to the provisions of the Plan. The rules, regulations andinterpretations made by the Plan Administrator shall, where appropriate, be applied on a consistent basis with respect to similarly situated Executives, andshall be final and binding on any Executive or former Executive and any successor in interest.The Plan Administrator may delegate any administrative duties, including, without limitation, duties with respect to the processing, review,investigation, approval and payment of severance pay and provision of severance benefits, to designated individuals or committees. The Plan Administratormay amend any Participant’s Severance Agreement to the extent the Plan Administrator determines it is reasonably necessary or appropriate to do so tocomply with section 409A of the Code. 26Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.10.CLAIMS PROCEDUREThe Plan Administrator shall determine the status of an individual as an Executive and the eligibility and rights of any Executive or former Executiveas a Participant to any severance pay or benefits hereunder. Any Executive or former Executive who believes that he or she is entitled to receive severancepay or benefits under the Plan, including severance pay or benefits other than those initially determined by the Plan Administrator, may file a claim in writingwith the Plan Administrator. Within 90 days after the receipt of the claim the Plan Administrator shall either allow or deny the claim in writing, unless specialcircumstances require an extension of time for processing, in which case a decision shall be rendered as soon as practicable, but not later than 180 days afterreceipt of a request for review.A claimant whose claim is denied (or his or her duly authorized representative) may, within 60 days after receipt of the denial of his or her claim,request a review upon written application to Exelon’s Chief Human Resources Officer or other officer designated by Exelon and specified in the claim denial;review (without charge) relevant documents; and submit written comments, documents, records and other information relating to the claim.The Chief Human Resources Officer or other designated officer shall notify the claimant of his or her decision on review within 60 days after receipt ofa request for review unless special circumstances require an extension of time for processing, in which case a decision shall be rendered as soon as possible,but not later than 120 days after receipt of a request for review. Notice of the decision on review shall be in writing. The officer’s decision on review shall befinal and binding on any claimant or any successor in interest.In reviewing a claim or an appeal of a claim denial, the Plan Administrator and the Chief Human Resources Officer or other designated by Exelon shallhave all of the powers and authority granted to the Plan Administrator pursuant to Section 9. 11.ARBITRATIONAny dispute, controversy or claim between the parties hereto concerning whether an Executive’s termination of employment for purposes of Section 5is based on either Good Reason or Cause may, after the claims procedure under Section 10 has been exhausted and at the election of the Executive, be settledby binding arbitration in Chicago, Illinois, before an impartial arbitrator pursuant to the rules and regulations of the American Arbitration Association(“AAA”) pertaining to the arbitration of employee benefit plan disputes. The costs and fees of the arbitrator shall be borne equally by the parties, regardless ofthe result of the arbitration. No arbitration shall be commenced after the date when institution of legal or equitable proceedings based upon such subjectmatter would be barred by the applicable statutes of limitations. Notwithstanding anything to the contrary contained in this Section or elsewhere in this Plan,any party may seek relief in the form of specific performance, injunctive or other equitable relief in order to enforce the decision of the arbitrator, and theCompany may seek injunctive relief to enforce the above-referenced statutes of limitations. 12.AMENDMENT OR TERMINATION OF PLANExelon’s Chief Human Resources Officer or another designated officer of the Company may amend, modify or terminate the Plan at any time by writteninstrument; provided, however, 27Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.that no amendment, modification or termination shall deprive any Participant of any payment or benefit that the Plan Administrator previously hasdetermined is payable under the Plan. Notwithstanding the foregoing, no amendment or termination that reduces the severance payments or materiallyadversely affects any Participant’s other benefits under Section 5 shall become effective as to such Participant during: (a) the 24-month period following aChange Date or (b) during an Imminent Control Change Period (unless such Participant consents to such termination or amendment). Any purported Plantermination or amendment in violation of this Section 12 shall be void and of no effect. 13.MISCELLANEOUS 13.1.Limitation on Rights. Participation in the Plan is limited to the individuals described in Sections 2 and 3, and the benefits under the Planshall not be payable with respect to any voluntary or involuntary termination of employment that is not a Termination of Employment. 13.2.Cooperation By Participants. During the Salary Continuation Period or Severance Period, as applicable, the Executive shall (a) be reasonablyavailable to the Company to respond to requests by them for information pertaining to or relating to matters which may be within theknowledge of the Executive and (b) cooperate with the Company in connection with any existing or future litigation or other proceedingsbrought by or against the Company, its subsidiaries or affiliates, to the extent the Company deems the Executive’s cooperation reasonablynecessary. 13.3.No Set-off by Company. This Section shall apply solely with respect to a Termination of Employment during a Post-Change Period or anImminent Control Change Period that culminates in a Change Date. Except as provided in Section 6, a Participant’s right to receive when duethe payments and other benefits provided for under Section 5 of this Plan is absolute, unconditional and subject to no setoff, counterclaim orlegal or equitable defense. 13.4.No Mitigation. A Participant shall not have any duty to mitigate the amounts payable by the Company under this Plan by seeking newemployment following termination. Except as specifically otherwise provided in this Plan, all amounts payable pursuant to this Plan shall bepaid without reduction regardless of any amounts of salary, compensation or other amounts which may be paid or payable to the Executive asthe result of the Executive’s employment by another, unaffiliated employer. 13.5.Headings. Headings of sections in this document are for convenience only, and do not constitute any part of the Plan. 13.6.Severability. If any one or more Sections, subsections or other portions of this Plan are declared by any court or governmental authority to beunlawful or invalid, such unlawfulness or invalidity shall not serve to invalidate any Section, subsection or other portion not so declared tobe unlawful or invalid. Any Section, subsection or other portion so declared to be unlawful or invalid shall be construed so as to effectuate theterms of such Section, subsection or other portion 28Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. to the fullest extent possible while remaining lawful and valid. Notwithstanding the foregoing, in the event a determination is made that theRestrictive Covenants are invalid or unenforceable in whole or in part, then the Severance Agreement with respect to the Participant subjectto such determination shall be void and the Company shall have no obligation to provide benefits under this Plan to such Participant. 13.7.Governing Law. The Plan shall be construed and enforced in accordance with the applicable provisions of ERISA and Section 409A of theCode. 13.8.No Right to Continued Employment. Nothing in this Plan shall guarantee the right of a Participant to continue in employment, and theCompany retains the right to terminate a Participant’s employment at any time for any reason or for no reason. 13.9.Successors and Assigns. This Plan shall be binding upon and inure to the benefit of Exelon and its successors and assigns and shall bebinding upon and inure to the benefit of a Participant and his or her legal representatives, heirs and legatees. Exelon shall cause any successorto assume the Plan. No rights, obligations or liabilities of a Participant hereunder shall be assignable without the prior written consent ofExelon Corporation. In the event of the death of a Participant prior to receipt of severance pay or benefits to which he or she is entitledhereunder (and, with respect to benefits under Section 4 or Section 5, after he or she has signed the Waiver and Release), the severance paydescribed in Sections 4.1, 5.1, or 5.2, as applicable, shall be paid to his or her estate, and the Participant’s dependents who are covered underany health care plans maintained by the Company shall be entitled to continued rights under Section 4.5 or Section 5.1(e) or Section 5.2(g),as applicable; provided that the estate or other successor of the Participant has not revoked such Waiver and Release. 13.10.Notices. All notices and other communications under this Plan shall be in writing and delivered by hand, by nationally-recognized deliveryservice that promises overnight delivery, or by first-class registered or certified mail, return receipt requested, postage prepaid, addressed asfollows:If to a Participant, to such Participant at his most recent home address on file with the Company.If to the Company: to the Plan Administrator.or to such other address as either party shall have furnished to the other in writing. Notice and communications shall be effective whenactually received by the addressee. 13.11.Number and Gender. Wherever appropriate, the singular shall include the plural, the plural shall include the singular, and the masculine shallinclude the feminine. 13.12.Tax Withholding. The Company may withhold from any amounts payable under this Plan or otherwise payable to a Participant or beneficiaryany Taxes the 29Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 determines to be appropriate under applicable law and may report all such amounts payable to such authority in accordance withany applicable law or regulation. 13.13.Section 409A. This Plan shall be interpreted and construed in a manner that avoids the imposition of additional taxes and penalties underSection 409A of the Code (“409A Penalties”). In the event the terms of this Plan would subject a Participant to 409A Penalties, the Companymay amend the terms of the Plan to avoid such 409A Penalties, to the extent possible. The payments to a Participant pursuant to this Plan areintended to be exempt from Section 409A of the Code to the maximum extent possible, under either the separation pay exemption pursuant toTreasury regulation §1.409A-1(b)(9)(iii) or as a short-term deferral pursuant to Treasury regulation §1.409A-1(b)(4), and for purposes of theseparation pay exemption, each installment paid to a Participant shall be considered a separate payment. Notwithstanding any other provisionin this Plan, if on the date of a Participant’s Termination Date the Participant is a Specified Employee, then to the extent any amount payableunder this Plan constitutes the payment of nonqualified deferred compensation, within the meaning of Section 409A of the Code, that underthe terms of this Plan would be payable prior to the six-month anniversary of the Termination Date, such payment shall be delayed until theearlier to occur of (A) the six-month anniversary of the Termination Date or (B) the date of the Participant’s death. Any reimbursement(including any advancement) payable to a Participant pursuant to this Plan shall be conditioned on the submission by the Participant of allexpense reports reasonably required by the Company under any applicable expense reimbursement policy, and shall be paid to the Participantwithin 30 days following receipt of such expense reports (or invoices), but in no event later than the last day of the calendar year followingthe calendar year in which the Participant incurred the reimbursable expense. Any amount of expenses eligible for reimbursement during acalendar year shall not affect the expenses eligibility for reimbursement during any other calendar year. The right to reimbursement pursuantto this Plan shall not be subject to liquidation or exchange for any other benefit. EXELON CORPORATIONBy: /s/ Amy E. Best Amy E. Best Senior Vice President and Chief Human Resources Officer 30Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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.“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 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Common Stock (which may be Restricted Stock), cash or a combination thereof with an aggregate value equal to the excess of the Fair Market Value of oneshare of Common Stock on the date of exercise over the base price of such SAR, multiplied by the number of such SARs which 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 6Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.conditions with respect to the award, such as limiting competitive employment or other activities. All such interpretations, rules, regulations and conditionsshall be conclusive and binding on all parties.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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 to Section1.5 of the Prior Plan, and reduced by the sum of the aggregate number of shares of Common Stock which become subject to outstanding options, outstandingFree-Standing SARs and outstanding Stock Awards granted under the Plan and shares of Common Stock delivered upon the settlement of Performance Unitsgranted under the Plan. To the extent that shares of Common Stock subject to an outstanding option, SAR or stock award granted under the Plan or anypredecessor plan are not issued or delivered by reason of the expiration, termination, cancellation or forfeiture of such award (excluding shares subject to anoption cancelled upon settlement in shares of a related tandem SAR or shares subject to a tandem SAR cancelled upon exercise of a related option), then suchshares of Common Stock shall again be available under this Plan. Shares of Common Stock to be delivered under this Plan shall be made available fromauthorized and unissued shares of Common Stock, or authorized and issued shares of Common Stock reacquired and held as treasury shares or otherwise or acombination 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 with Section3.2(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 Restricted Stockshall 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 Common Stock,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 Stock subjectto 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 this Section2.3, 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 of employment(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 the holder for GoodReason, such holder’s outstanding options shall immediately become fully exercisable and may thereafter be exercised by such holder (or such holder’s legalrepresentative or similar person) until and including the earlier to occur of (A) the date which is five years after the effective date of such holder’s terminationof 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Restriction Periodapplicable to some or all outstanding Restricted Stock Awards and Restricted Stock Unit Awards shall lapse in full or in part, (C) the PerformancePeriod applicable to some or all outstanding Performance Share Awards and Performance Unit Awards shall lapse in full or in part, and (D) thePerformance Measures applicable to some or all outstanding awards shall be deemed to be satisfied at the target or any other level not exceeding themaximum 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 such awardas 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 by theCompany, 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, the number ofshares of Common Stock then subject to the portion of such option or SAR surrendered, to the extent such option or SAR is then exercisable orbecomes exercisable pursuant to clause (i), multiplied by the excess, if any, of the Fair Market Value of a share of Common Stock as of the date of theCorporate Transaction, over the purchase price or base 18Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 then subjectto the portion of such award surrendered, to the extent the Restriction Period and Performance Period, if any, on such Stock Award have lapsed or willlapse pursuant to clause (i) and to the extent that the Performance Measures, if any, have been satisfied or are deemed satisfied pursuant 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 the case of a Performance UnitAward, the value of the Performance Units then subject to the portion of such award surrendered, to the extent the Performance Period applicable sosuch award has lapsed or will lapse pursuant to clause (i) and to the extent the Performance Measures applicable to such award have been satisfied orare deemed satisfied pursuant to clause (i); (B) shares of capital stock of the corporation resulting from such Corporate Transaction, or a parentcorporation thereof, having a fair market value not less than the amount determined under clause (A) above; or (C) a combination of the payment ofcash 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 Voting Securitiesrepresenting 20% or more of the combined voting power of all the then outstanding Voting Securities of the Company (such an SEC Person, a “20%Owner”); provided, however, that for purposes of this subsection (i), the following acquisitions shall not constitute a Change in Control: (1) anyacquisition directly from the Company (excluding any acquisition resulting from the exercise of an exercise, conversion or exchange privilege unlessthe security being so exercised, converted or exchanged was acquired directly from the Company), (2) any acquisition by the Company, (3) anyacquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company (a“Company Plan”), or (4) any acquisition by any corporation pursuant to a transaction which complies with paragraphs (A), (B) and (C) ofsubsection (iii) of this definition; provided further, that for purposes of clause (2), if any 20% Owner of the Company other than the Company or anyCompany Plan becomes a 20% Owner by reason of an acquisition by the Company, and such 20% Owner of the Company shall, after such acquisitionby the Company, become the Beneficial Owner of any additional outstanding common shares of the Company or any additional outstanding VotingSecurities of the Company (other than pursuant to any dividend reinvestment plan or arrangement maintained by the Company) and such beneficialownership is publicly announced, such additional beneficial ownership shall constitute a Change in Control; or 19Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 least amajority 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 the IncumbentBoard shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individualwhose initial assumption of office occurs as a result of an actual or threatened election contest (as such terms are used in Rule 14a-11 promulgatedunder the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other 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 common stock ofCompany and outstanding Voting Securities of the Company immediately prior to such Corporate Transaction beneficially own, directly orindirectly, more than 60% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from suchCorporate Transaction (including, without limitation, a corporation which, as a result of such transaction, owns the Company or all orsubstantially all of the assets of the Company either directly or through one or more subsidiaries) in substantially the same proportions as theirownership immediately prior to such Corporate Transaction of the outstanding common stock of Company and outstanding Voting Securities ofthe Company, as the case may be;(B) no SEC Person (other than the corporation resulting from such Corporate Transaction, and any Person which beneficially owned,immediately prior to such corporate Transaction, directly or indirectly, 20% or more of the outstanding common stock of the Company or theoutstanding Voting Securities of the Company, as the case may be) becomes a 20% Owner, directly or indirectly, of the then-outstandingcommon stock of the corporation resulting from such Corporate Transaction or the combined voting power of the outstanding voting securitiesof such corporation; and(C) individuals who were members of the Incumbent Board will constitute at least a majority of the members of the board of directors ofthe corporation resulting from such Corporate Transaction; or(iv) Approval by the Company’s shareholders of a plan of complete liquidation or dissolution of the Company, other than a plan of liquidationor dissolution which results in the acquisition of all or substantially all of the assets of the Company by an affiliated company. 20Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 shall bedeemed a part of, and govern, equity compensation awards granted by Exelon Corporation, a Pennsylvania corporation (the “Company”), on or after January1, 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 forth thetype 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 as newhires, 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 of CommonStock.(h) “Earned Shares” shall mean shares of Common Stock (or cash representing shares, as applicable) subject to a Performance Share Unit Awardthat are earned based on the achievement of the performance goals for the applicable Performance Cycle (or portion thereof, in the case of TransitionAwards).(i) “Effective Date” shall mean January 1, 2011.Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 vesting conditionsset 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 period beginning onJanuary 1 of the year in which the Award is granted (and any applicable look-back period), (B) for the Transition Awards, the two-year periodbeginning 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 cash subject tothe 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 vesting conditionsset forth in Section 4 of this Program.(r) “Restrictive Covenants” shall mean any noncompetition, nonsolicitation, confidentiality, intellectual property or other restrictive covenantsto which a Participant is subject, required as a condition to receipt of an Award, or which is contained in any other agreement between the Participantand 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 may grantPerformance Share Unit Awards to employees who are employed in a Vice President or more senior position, including without limitation Nuclear PlantManagers, as selected by the Committee in its sole discretion. Effective January 1, 2014, the Committee may grant Performance Cash Units in lieu ofPerformance 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 after January1, 2013, at the end of the Performance Cycle, the number of Earned Shares is determined based on the average of the annual performance results,subject to adjustment as set forth in the Program summary and/or administrative guidelines. Notwithstanding the foregoing, the maximum number ofshares of Common Stock that may become subject to Performance Share Unit Awards granted in any calendar year to Participants the Company hasdetermined as of the Grant Date may be “covered employees” (within the meaning of Section 162(m)(3) of the Code) for such year or for anysubsequent 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2013shall become vested (i) on the date of the first regular meeting of the Committee held in the calendar year following the calendar year in whichthe Grant Date occurs with respect to one-third of the number of Earned Shares, (ii) on the date of the first regular meeting of the Committee heldin the second calendar year following the calendar in which the Grant Date occurs with respect to an additional one-third of the number ofEarned Shares, and (iii) on the date of the first regular meeting of the Committee held in the third calendar year following the calendar year inwhich the Grant Date occurs with respect to the remaining Earned Shares (but, with respect to each such year, not later than March 15), in eachcase subject to the Participant’s continuous employment with the Company through the applicable 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 be earnedand 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) withrespect to the Second Tranche, on the date of the first regular meeting of the Committee held in 2015 (but, with respect to each such year, notlater than March 15), in each case subject to the Participant’s continuous employment with the Company through the applicable 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, PerformanceShare Units and Performance Cash Units subject to an Award (other than a Transition Award) and granted on or after January 1, 2013 shall beearned and become fully vested on the date of the first regular meeting of the Committee held in the third calendar year following the calendaryear in which the Grant Date occurs (but, with respect to each such Performance Cycle, not later than March 15 of such year), in each case subjectto the Participant’s continuous employment with the Company through the applicable vesting date.(d) Dividend Equivalents. As of each Dividend Payment Date, the Company shall pay to the Participant a cash payment in an amount equal tothe dollar amount of the cash dividend paid per share of Common Stock multiplied by the number of Earned Shares that are subject to a PerformanceShare Unit Award immediately prior to the record date for such Dividend Payment Date, but that have not been issued pursuant to Section 3(e) as ofsuch record date. 4Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 vesting of aPerformance 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 issue ortransfer to the Participant the number of Earned Shares that have become vested. The Company may effect such transfer either by the delivery of one ormore certificates of Common Stock to the Participant or by an appropriate entry on the books of the Company or of a duly authorized transfer agent ofthe 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 and designatedin 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 Executive Vice President orabove and who has achieved 200% or more of his or her stock ownership target by September 30 of the calendar year prior to payout of the Award shallbe paid in cash. The Company shall pay all original issue or transfer taxes and all fees and expenses incident to such delivery, except as otherwiseprovided in Section 8 of the Program. Prior to the settlement of a Performance Share Unit Award, the holder of such Award shall have no rights as astockholder of the Company with respect to the shares of Common Stock subject to such Award. Performance Cash Awards shall be paid in cash uponvesting. Notwithstanding the foregoing, if a Participant is a “Specified Employee,” within the meaning of section 409A of the Code, and suchParticipant is or will become eligible for Retirement prior to the calendar year in which the Performance Share Unit Award is scheduled to become fullyvested, then any Earned Shares subject to the Award or payment under a Performance Cash Unit which become vested upon the Participant’stermination of employment in accordance with Section 3(f) of this Program shall be issued to the Participant as of the earlier to occur of the six-monthanniversary 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 by theCompany for a reason other than Cause, and such Participant has not breached his or her obligations to the Company or any of its affiliates underany Restrictive Covenant, then all Earned Shares subject to such Participant’s Performance Share Unit Award and earned cash subject to aPerformance Cash Unit shall become fully vested as of the effective date of the Participant’s termination of employment or date of death, as thecase may be. To the extent the Award has not been earned as of the date of the Participant’s termination of employment or death (i.e. as to whichthe current Performance Cycle has not elapsed), the Participant shall become 5Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 fully vested withrespect to such an Award for 2012 upon an involuntary termination without Cause) and the extent to which the Company performance goalsestablished under the Program for such Performance Cycle are attained as of the last day of the year in which the termination date occurs (andassuming a 100% individual performance multiplier), and such Award shall be payable as of the date the first third of the Awards for suchPerformance 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 (Including TransitionAwards). If a Participant’s employment with the Company terminates by reason of Retirement, Disability, death or an involuntary termination ofemployment by the Company for a reason other than Cause, and such Participant has not breached his or her obligations to the Company or anyof its affiliates under any Restrictive Covenant, then (A) if such event occurs within the first 12 months of the Performance Cycle, then theParticipant shall earn and become vested in a pro-rated Award (both First and Second Tranches, in the case of Bridge Awards) based on thenumber of elapsed days in such 12-month period as of the termination date (pro-ration determined by dividing the number of elapsed days by365) and the extent to which the performance goals established under the Program for such Performance Cycle (or portion thereof, in the case ofthe Transition Awards) are attained, and (B) if such event occurs after the first 12 months of the Performance Cycle, then the Participant shallbecome fully vested in all Earned Shares (the number determined in accordance with Section 3(b) above) or earned cash, as applicable. In eitherevent, the Earned Shares or cash shall be payable on the next payout date applicable to Participants who remain actively employed with theCompany (either the payout date for the 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 in clause (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 under any RestrictiveCovenant, the unvested portion of such Participant’s Award shall be forfeited and terminate as of the date of such termination 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 a Participantwho 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 such Participantuntil 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 suchAward actually vests earlier pursuant to Section 3(f)) or (ii) the date of the Participant’s death, regardless of when such shares are issued or transferred tosuch Participant. Effective January 1, 2013, this provision shall no longer be effective. 6Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 or otherexecutive position (including without limitation Nuclear Plant Managers) below the Senior Vice President level, and (ii) key managers and other selectmanagement 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 and conditions, notinconsistent 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 be determined bythe 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Stock UnitAward 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 vesting of aRestricted 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, andsuch Participant has not breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, then all shares ofCommon Stock subject to such Participant’s Restricted Stock Unit Award shall become fully vested as of the effective date of the Participant’stermination 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 in clause (i) ofthis Section 4(g) or if the Participant has breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant,the 8Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 more seniorposition, 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 and conditions, notinconsistent 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 set forth inthe 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 of suchOption 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 employment pursuant toSection 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 thenumber 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 an additional 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 with respect to anadditional 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 the Grant Datewith 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 the Company(or its designated agent) specifying the number of whole shares of Common Stock to be purchased and accompanying such notice with payment therefor infull, 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 Stock having a Fair Market Value, determined as of the date of exercise, equal to theaggregate 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, each Optionheld by such Participant shall be fully exercisable, and may thereafter be exercised by such Participant (or such Participant’s legal representativeor similar person) until and including the earlier to occur of (i) the fifth anniversary of the effective date of such Participant’s termination ofemployment 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 be fullyexercisable, and may thereafter be exercised by such Participant’s executor, administrator, legal representative, beneficiary or similar person untiland 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 held by suchParticipant shall be cancelled and cease to be exercisable as of the earlier to occur of (i) the effective date of such termination of employment and(ii) the date on which the Participant first engaged in conduct giving rise to a termination for Cause, and the Company thereafter may require therepayment of any amounts received by such Participant in connection with an exercise of such Option following 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 such Option isexercisable on the effective date of such Participant’s termination of employment, and may thereafter be exercised by such Participant (or suchParticipant’s legal representative or similar person) until and including the earlier to occur of (i) the date which is 90 days after the effective dateof such Participant’s termination of employment and (ii) the Expiration Date. 10Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 in clause(iv), each Option held by such Participant shall be exercisable only to the extent that such Option is exercisable on the date of such Participant’sdeath and may thereafter be exercised by the Participant’s executor, administrator, legal representative, beneficiary or similar person until andincluding the earlier to occur of (i) the first anniversary of the date of death and (ii) the expiration date of the term of such Option. (vi)Breach of Restrictive Covenant. Notwithstanding clauses (i) through (v), if a Participant breaches his or her obligations to the Company or any ofits affiliates under a Restrictive Covenant, each Option held by such Participant shall be cancelled and cease to be exercisable as of the date onwhich the Participant first breached such Restrictive Covenant, and the Company thereafter may require the repayment of any amounts receivedby 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 individual change incontrol agreement or severance plan, and notwithstanding any other provision of this Section 5(g), if within 24 months following a Change inControl, the Company ceases to employ a Participant due to a termination of employment (i) by the Company other than for Cause, or (ii) withrespect to a Participant whose position is at grade level E09 (or its equivalent), by the Participant for Good Reason, such Participant’soutstanding Options shall immediately become 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 (A) the fifth anniversary of the effective date of such Participant’stermination 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 theextent not earlier exercised or terminated pursuant to Section 5(g), on the Expiration Date. Upon the termination of the Option, the Option and all rightsthereunder 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 11Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.process or domestic relations order. Upon any attempt so to sell, transfer, assign, pledge, hypothecate, encumber or otherwise dispose of an Award, suchAward and all rights thereunder shall immediately become null and void.8. Withholding Taxes. The Company shall have the right to require, prior to the issuance or delivery of any shares of Common Stock or the payment ofany cash pursuant to an Award, or upon the vesting of any Award that is considered deferred compensation, payment by the Participant of any federal, 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 of CommonStock which would otherwise be delivered to a Participant, having an aggregate Fair Market Value determined as of the Tax Date, or withhold an amount ofcash which would otherwise be payable to a Participant, in the amount necessary to satisfy any such obligation. The Participant may elect to satisfy any suchobligation by any of the following means, to the extent permitted by the Administrator: (A) a cash payment to the Company, (B) authorizing the Company towithhold whole shares of Common Stock which would otherwise be delivered having an aggregate Fair Market Value, determined as of the Tax Date, orwithhold an amount of cash which would otherwise be payable to the Participant, equal to the amount necessary to satisfy any such obligation, (C) in thecase 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 Company to whomthe Participant has submitted an irrevocable notice of exercise or (D) any combination of (A) and (B). Shares of Common Stock to be delivered or withheldmay not have an aggregate Fair Market Value in excess of the amount determined by applying the minimum statutory withholding rate. Any fraction of ashare of Common Stock which would be required to satisfy such an obligation shall be disregarded and the remaining amount due shall be paid in cash bythe 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 subject tosuch 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 shall beinterpreted in accordance therewith. Notwithstanding any provision of the Program to the contrary, each Award shall be subject to a clawback pursuant to theExelon Executive Officer Compensation Recoupment Policy contained in the Exelon Corporation Board of Directors Corporate Governance Principles, as ineffect 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 acquired uponthe 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 of 1933, asamended (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”). Except forauthority 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 Company andany 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 be made,if to the Company, to Exelon Corporation, 10 South Dearborn Street, Chicago, Illinois 60603, Attention: Vice President, Corporate Compensation, andif to the Participant, to his or her then current work location. All notices, requests or other communications provided for in this Program shall be madein writing either (a) by personal delivery to the party entitled thereto, (b) by facsimile with confirmation of receipt, (c) by mailing in the United Statesmails to the last known address of the party entitled thereto or (d) by express courier service. The notice, request or other communication shall bedeemed to be received upon personal delivery, upon confirmation of receipt of facsimile transmission, or upon receipt by the party entitled thereto ifby United States mail or express courier service; provided, however, that if a notice, request or other communication is not received during regularbusiness 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 the Code andshall be interpreted and construed consistently with such intent. Awards granted pursuant to this Program are also intended to be exempt from Section409A of the Code to the maximum extent possible as short-term deferrals pursuant to Treasury regulation §1.409A-1(b)(4), and for this purpose eachpayment shall be considered a separate payment. In the event the terms of an Award would subject a Participant to taxes or penalties under Section409A of the Code (“409A Penalties”), the Company may modify the terms of such Award to avoid such 409A Penalties, to the extent possible;provided that in no event shall the Company be responsible for any 409A Penalties that arise in connection with any Award. To the extent the timingof payment under an Award is determined by reference to a Participant’s “termination of employment,” such term shall be deemed to refer to theParticipant’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 that theChief Human Resources Officer or the Vice President, Corporate Compensation, of the Company may amend the Program to comply with applicablelaw, 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, to theextent 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10.34.2EXELON CORPORATIONLONG-TERM INCENTIVE PROGRAM(As amended and restated as of January 1, 2015)1. Purpose. The purpose of this Exelon Corporation Long-Term Incentive Program (the “Program”) is to set forth certain provisions which shall bedeemed a part of, and govern, equity compensation awards granted by Exelon Corporation, a Pennsylvania corporation (the “Company”), on or after January1, 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 forth thetype 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 as newhires, 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 of CommonStock.(h) “Earned Cash” shall be the dollar amount of cash subject to a Performance Cash Unit Award that have been earned based on the achievementof the performance goals for the applicable Performance Cycle).(i) “Earned Shares” shall mean shares of Common Stock (or cash representing shares, as applicable) subject to a Performance Share Unit Awardthat have been earned based on the achievement of the performance goals for the applicable Performance Cycle (or portion thereof, in the case ofTransition Awards).Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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) “Effective Date” shall mean January 1, 2011.(k) “First Tranche” shall mean one-third of the Performance Share Units granted under a Transition Award.(l) “Grant Date” shall mean the date on which an Award is granted, as set forth in the applicable Award Notice.(m) “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.(n) “Participant” shall mean the recipient of an Award granted under this Program.(o) “Performance Cycle” shall mean (A) for Performance Share Unit Awards granted prior to January 1, 2013, the one-year period beginning onJanuary 1 of the year in which the Award is granted (and any applicable look-back period), (B) for the Transition Awards, the two-year periodbeginning 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.(p) “Performance Cash Unit” shall mean a right granted to a Participant employed in a Utility Company to receive an amount of cash subject tothe achievement of the applicable performance goals and the satisfaction of the vesting conditions set forth in Section 3 of this Program.(q) “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.(r) “Restricted Stock Unit” shall mean a right to receive shares of Common Stock upon and subject to the satisfaction of the vesting conditionsset forth in Section 4 of this Program.(s) “Restrictive Covenants” shall mean any noncompetition, nonsolicitation, confidentiality, intellectual property or other restrictive covenantsto which a Participant is subject, required as a condition to receipt of an Award, or which is contained in any other agreement between the Participantand the Company or any of its affiliates.(t) “Retirement” shall mean a Participant’s termination of employment (other than a termination upon death, disability or involuntarytermination for cause) on or 2Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.after the date as of which the Participant has attained age 55 (age 50 with respect to Awards granted prior to January 1, 2013) and completed at least tenyears of service with the Company and the Subsidiaries. For purposes of this definition, the holder’s age and service shall be determined taking intoaccount any deemed age or service awarded to the holder for benefit accrual purposes under any nonqualified defined benefit retirement plan of theCompany in which the holder is a participant.(u) “Second Tranche” shall mean two-thirds of the Performance Share Units granted under a Transition Award(v) “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 (or later, with respect to a new hire or promotion) of each Performance Cycle beginning on orafter the Effective Date, the Committee may grant Performance Share Unit Awards to employees who are employed in a Vice President or more seniorposition, including without limitation Nuclear Plant Managers, as selected by the Committee in its sole discretion. Effective January 1, 2014, theCommittee may grant Performance Cash Units in lieu of Performance Share Unit Awards to such designated employees who are employed in a UtilityCompany. Performance Share Unit Awards and Performance Cash Unit Awards shall be subject to the respective applicable terms and conditions setforth in this Section 3, and shall contain such additional terms and conditions, not inconsistent with the terms of this Program, as the Committee shalldeem advisable and set forth in the applicable Program summary or Award Notice.(b) Number of Shares (or Amount of Cash) and Other Terms. The number of shares of Common Stock represented by a Performance Share UnitAward, and the amount of cash represented by a Performance Cash Award, for any Performance Cycle shall be determined based on the achievement ofperformance goals established by the Committee and set forth in the Program summary for such Performance Cycle and the administrative guidelinesapproved by the Committee. Each performance goal shall be assigned a weighting and scored at the end of each calendar year within the PerformanceCycle. For Performance Cycles beginning on or after January 1, 2013, at the end of the Performance Cycle, the number of Earned Shares (or the amountof Earned Cash) is determined based on the average of the annual performance results, subject to adjustment as set forth in the Program summary and/oradministrative guidelines. Notwithstanding the foregoing, the maximum number of shares of Common Stock that may become subject to PerformanceShare Unit Awards and Performance Cash Awards granted in any calendar year to Participants the Company 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 for any subsequent year in which such Award may beoutstanding, shall be equal to the lesser of (i) the number determined by (A) multiplying 1.5% of the Company’s Operating Income for such year by 3Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 allocation percentage approved by Committee for such Participant within the first 90 days of the applicable Performance Cycle and (B) dividingsuch dollar amount by the closing price of a share of Common Stock on the last trading day of such year and (ii) the per person limit set forth in Section1.6 of the Plan. For purposes of this Section 3(b), the “Operating Income” of the Company for such year shall be as reported in the Company’s financialstatements for such year according to generally accepted accounting principles and as reviewed or accepted, as the case may be, by the Company’sindependent public accountants, and certified by the Committee in accordance with section 162(m) of the Code. The Committee reserves the right inits sole discretion to determine that the number of Earned Shares for any Performance Cycle shall be zero in the event of materially adverse business orfinancial 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, 2013shall become vested (i) on the date of the first regular meeting of the Committee held in the calendar year following the calendar year in whichthe Grant Date occurs with respect to one-third of the number of Earned Shares, (ii) on the date of the first regular meeting of the Committee heldin the second calendar year following the calendar in which the Grant Date occurs with respect to an additional one-third of the number ofEarned Shares, and (iii) on the date of the first regular meeting of the Committee held in the third calendar year following the calendar year inwhich the Grant Date occurs with respect to the remaining Earned Shares (but, with respect to each such year, not later than March 15), in eachcase subject to the Participant’s continuous employment with the Company through the applicable 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 be earnedand 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) withrespect to the Second Tranche, on the date of the first regular meeting of the Committee held in 2015 (but, with respect to each such year, notlater than March 15), in each case subject to the Participant’s continuous employment with the Company through the applicable 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, PerformanceShare Units and Performance Cash Units subject to an Award (other than a Transition Award) and granted on or after January 1, 2013 shall beearned and become fully vested on the date of the first regular meeting of the Committee held in the third calendar year following the calendaryear in which the Grant Date occurs (but, with respect to each such Performance Cycle, not later than March 15 of such year), in each case subjectto the Participant’s continuous employment with the Company through the applicable vesting date. 4Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(d) Dividend Equivalents. As of each Dividend Payment Date, the Company shall pay to the Participant a cash payment in an amount equal tothe dollar amount of the cash dividend paid per share of Common Stock multiplied by the number of Earned Shares (if any) 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 to Section3(e) as of such record date.(e) Settlement of Vested Awards. Subject to the withholding of taxes pursuant to Section 8 of the Program, within 30 days after the vesting of aPerformance 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 issue ortransfer to the Participant the number of Earned Shares that have become vested. The Company may effect such transfer either by the delivery of one ormore certificates of Common Stock to the Participant or by an appropriate entry on the books of the Company or of a duly authorized transfer agent ofthe 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 and designatedin 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 Executive Vice President orabove and who has achieved 200% or more of his or her stock ownership target by September 30 of the calendar year prior to payout of the Award shallbe paid in cash. The Company shall pay all original issue or transfer taxes and all fees and expenses incident to such delivery, except as otherwiseprovided in Section 8 of the Program. Prior to the settlement of a Performance Share Unit Award, the holder of such Award shall have no rights as astockholder of the Company with respect to the shares of Common Stock subject to such Award. Performance Cash Unit Awards shall be paid in cashupon vesting. Notwithstanding the foregoing, if a Participant is a “Specified Employee,” within the meaning of section 409A of the Code, and suchParticipant is or will become eligible for Retirement prior to the calendar year in which the Performance Share Unit Award is scheduled to become fullyvested, then any Earned Shares subject to the Award or payment under a Performance Cash Unit which become vested upon the Participant’stermination of employment in accordance with Section 3(f) of this Program shall be issued to the Participant as of the earlier to occur of the six-monthanniversary 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 by theCompany for a reason other than Cause, and such Participant has not breached his or her obligations to the Company or any of its affiliates underany Restrictive Covenant, then all Earned Shares subject to such Participant’s 5Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Share Unit Award and earned cash subject to a Performance Cash Unit shall become fully vested as of the effective date of theParticipant’s termination of employment or date of death, as the case may be. To the extent the Award has not been earned as of the date of theParticipant’s termination of employment or death (i.e. as to which the current Performance Cycle has not elapsed), the Participant shall becomevested in a pro-rated Award based on the number of elapsed days in the current Performance Cycle as of the termination date (or fully vested withrespect to such an Award for 2012 upon an involuntary termination without Cause) and the extent to which the Company performance goalsestablished under the Program for such Performance Cycle are attained as of the last day of the year in which the termination date occurs (andassuming a 100% individual performance multiplier), and such Award shall be payable as of the date the first third of the Awards for suchPerformance 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 (Including TransitionAwards). If a Participant’s employment with the Company terminates by reason of Retirement, Disability, death or an involuntary termination ofemployment by the Company for a reason other than Cause, and such Participant has not breached his or her obligations to the Company or anyof its affiliates under any Restrictive Covenant, then (A) if such event occurs within the first 12 months of the Performance Cycle, then theParticipant shall earn and become vested in a pro-rated Award (both First and Second Tranches, in the case of Bridge Awards) based on thenumber of elapsed days in such 12-month period as of the termination date (pro-ration determined by dividing the number of elapsed days by365) and the extent to which the performance goals established under the Program for such Performance Cycle (or portion thereof, in the case ofthe Transition Awards) are attained, and (B) if such event occurs after the first 12 months of the Performance Cycle, then the Participant shallbecome fully vested in all Earned Shares (the number determined in accordance with Section 3(b) above) or earned cash, as applicable. In eitherevent, the Earned Shares or cash shall be payable on the next payout date applicable to Participants who remain actively employed with theCompany (either the payout date for the 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 in clause (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 under any RestrictiveCovenant, the unvested portion of such Participant’s Award shall be forfeited and terminate as of the date of such termination of employment. 6Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(g) Restriction on Sale of Shares by Senior Officers. Shares of Common Stock issued under an Award pursuant to Section 3(e) to a Participantwho 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 such Participantuntil 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 suchAward actually vests earlier pursuant to Section 3(f)) or (ii) the date of the Participant’s death, regardless of when such shares are issued or transferred tosuch Participant. Effective January 1, 2013, this provision shall no longer be effective.(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, and Constellation Short-Term Incentives and Commissions Payable as Restricted Stock Units.(a) Granting of Awards. The Committee may grant Restricted Stock Unit Awards to employees who are employed (i) in a Vice President or otherexecutive position (including without limitation Nuclear Plant Managers) below the Senior Vice President level, and (ii) key managers and other selectmanagement 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 and conditions, notinconsistent 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 be determined bythe Committee and set forth in the applicable Program summary or Award Notice (which may reference a number of shares or cash value).(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 7Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Date, (ii) on the date of the first regular meeting of the Committee in the second calendar year following the calendar year in which the Grant Dateoccurs with respect to an additional one-third of the number of shares of Common Stock subject to the Award on the Grant Date, and (iii) on the date ofthe first regular meeting of the Committee in the third calendar year following the calendar year in which the Grant Date occurs with respect to theremaining shares of Common Stock subject to the Award on the Grant Date (but, with respect to each such year, not later than March 15), in each casesubject to the Participant’s continuous employment with the Company through the applicable vesting date.(e) Dividend Equivalents. As of each Dividend Payment Date, the number of shares of Common Stock that are subject to a Restricted Stock UnitAward 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 vesting of aRestricted 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, andsuch Participant has not breached his or her obligations to the Company or 8Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results. any of its affiliates under any Restrictive Covenant, then all shares of Common Stock subject to such Participant’s Restricted Stock Unit Awardshall become fully vested as of the effective date of 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 in clause (i) ofthis Section 4(g) or if the Participant has breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant,the 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 more seniorposition, 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 and conditions, notinconsistent 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 set forth inthe 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 of suchOption 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 employment pursuant toSection 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 thenumber 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 an additional 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 with respect to anadditional 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 the Grant Datewith 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. 9Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.(f) Method of Exercise. To the extent permitted by the Administrator, a Participant may exercise an Option (i) by giving written notice to the Company(or its designated agent) specifying the number of whole shares of Common Stock to be purchased and accompanying such notice with payment therefor infull, 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 Stock having a Fair Market Value, determined as of the date of exercise, equal to theaggregate purchase price payable by reason of such exercise, (C) authorizing the Company to withhold whole shares of Common Stock which wouldotherwise be delivered having an aggregate Fair Market Value, determined as of the date of exercise, equal to the amount necessary to satisfy such obligation,provided that the Committee determines that such withholding of shares does not cause the Company to recognize an increased compensation expense underapplicable accounting principles, (D) except as may be prohibited by applicable law, in cash by a broker-dealer acceptable to the Company to whom theParticipant has submitted an irrevocable notice of exercise or (E) a combination of (A), (B) and (C) and (ii) by executing such documents as the Companymay 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, each Optionheld by such Participant shall be fully exercisable, and may thereafter be exercised by such Participant (or such Participant’s legal representativeor similar person) until and including the earlier to occur of (i) the fifth anniversary of the effective date of such Participant’s termination ofemployment 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 be fullyexercisable, and may thereafter be exercised by such Participant’s executor, administrator, legal representative, beneficiary or similar person untiland 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 held by suchParticipant shall be cancelled and cease to be exercisable as of the earlier to occur of (i) the effective date of such termination of employment and(ii) the date on which the Participant first engaged in conduct giving rise to a termination for Cause, and the Company thereafter may require therepayment of any amounts received by such Participant in connection with an exercise of such Option following such cancellation date. 10Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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)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 such Option isexercisable on the effective date of such Participant’s termination of employment, and may thereafter be exercised by such Participant (or suchParticipant’s legal representative or similar person) until and including the earlier to occur of (i) the date which is 90 days after the effective dateof such Participant’s termination of employment and (ii) the Expiration Date. (v)Death Following Termination of Employment. If a Participant dies during the applicable post-termination exercise period described in clause(iv), each Option held by such Participant shall be exercisable only to the extent that such Option is exercisable on the date of such Participant’sdeath and may thereafter be exercised by the Participant’s executor, administrator, legal representative, beneficiary or similar person until andincluding the earlier to occur of (i) the first anniversary of the date of death and (ii) the expiration date of the term of such Option. (vi)Breach of Restrictive Covenant. Notwithstanding clauses (i) through (v), if a Participant breaches his or her obligations to the Company or any ofits affiliates under a Restrictive Covenant, each Option held by such Participant shall be cancelled and cease to be exercisable as of the date onwhich the Participant first breached such Restrictive Covenant, and the Company thereafter may require the repayment of any amounts receivedby such Participant in connection with an exercise of such Option following such cancellation 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 theextent not earlier exercised or terminated pursuant to Section 5(g), on the Expiration Date. Upon the termination of the Option, the Option and all rightsthereunder 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 the payment ofany cash pursuant to an Award, or upon the vesting of any Award that is considered deferred compensation, payment by the Participant of any federal, 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 of CommonStock which would otherwise be delivered to a Participant, having an aggregate Fair Market Value determined as of the Tax Date, or withhold an amount ofcash which would otherwise be payable to a Participant, in the amount necessary to satisfy any such obligation. The Participant may elect to satisfy any suchobligation by any of the following means, to the extent permitted by the Administrator: (A) a cash payment to the Company, (B) authorizing the Company towithhold whole shares of Common Stock which would otherwise be delivered having an aggregate Fair Market Value, determined as of the Tax Date, orwithhold an amount of cash which would otherwise be payable to the Participant, equal to the amount necessary to satisfy any such obligation, (C) in thecase 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 Company to whomthe Participant has submitted an irrevocable notice of exercise or (D) any combination of (A) and (B). Shares of Common Stock to be delivered or withheldmay not have an aggregate Fair Market Value in excess of the amount determined by applying the minimum statutory withholding rate. Any fraction of ashare of Common Stock which would be required to satisfy such an obligation shall be disregarded and the remaining amount due shall be paid in cash bythe Participant.9. Adjustment; Change in Control or Corporate Transaction. The number and class of securities subject to an Award shall be subject to adjustment asprovided in Section 5.7 of the Plan. In the event of a Change in Control or Corporate Transaction, Awards shall be subject to the terms of Section 5.8 of thePlan, as determined by the Committee. The decision of the Committee regarding any such adjustment, Change in Control and/or Corporate Transaction shallbe 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 subject tosuch 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 shall beinterpreted in accordance therewith. Notwithstanding any provision of the Program to the contrary, each Award shall be subject to a clawback pursuant to theExelon Executive Officer Compensation Recoupment Policy contained in the Exelon Corporation Board of Directors Corporate Governance Principles, as ineffect 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 acquired uponthe 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 of 1933, asamended (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”). Except forauthority 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. The Administrator may adoptsuch rules and procedures as it deems appropriate for the administration of the Plan, including but not limited to rules and procedures governing theadministration and treatment (e.g., pro-ration, vesting, etc.) of Awards to Participants in situations involving transfers between business units and eligible andineligible positions, which may be set forth in the applicable Program summary or Award Notice.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 Company andany 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 be made,if to the Company, to Exelon Corporation, 10 South Dearborn Street, Chicago, Illinois 60603, Attention: Vice President, Corporate Compensation, andif to the Participant, to his or her then current work location. All notices, requests or other communications provided for in this Program shall be madein writing either (a) by personal delivery to the party entitled thereto, (b) by facsimile with confirmation of receipt, (c) by mailing in the United Statesmails to the last 13Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.known address of the party entitled thereto or (d) by express courier service. The notice, request or other communication shall be deemed to be receivedupon personal delivery, upon confirmation of receipt of facsimile transmission, or upon receipt by the party entitled thereto if by United States mail orexpress courier service; provided, however, that if a notice, request or other communication is not received during regular business hours, it shall bedeemed to be received on the next succeeding business day of the Company.(c) Section 409A. This Program and the Awards granted hereunder are intended to comply with the requirements of section 409A of the Code andshall be interpreted and construed consistently with such intent. Awards granted pursuant to this Program are also intended to be exempt from Section409A of the Code to the maximum extent possible as short-term deferrals pursuant to Treasury regulation §1.409A-1(b)(4), and for this purpose eachpayment shall be considered a separate payment. In the event the terms of an Award would subject a Participant to taxes or penalties under Section409A of the Code (“409A Penalties”), the Company may modify the terms of such Award to avoid such 409A Penalties, to the extent possible;provided that in no event shall the Company be responsible for any 409A Penalties that arise in connection with any Award. To the extent the timingof payment under an Award is determined by reference to a Participant’s “termination of employment,” such term shall be deemed to refer to theParticipant’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 that theChief Human Resources Officer or the Vice President, Corporate Compensation, of the Company may amend the Program to comply with applicablelaw, 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, to theextent 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015. EXELON CORPORATIONBy: Senior Vice President & Chief Human Resources Officer 15Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10.34.3AMENDMENT NUMBER TWOTO THE EXELON CORPORATION2011 LONG-TERM INCENTIVE PLANWHEREAS, Exelon Corporation (the “Company”) maintains the Exelon Corporation 2011 Long-Term Incentive Plan, effective January 1, 2011, asamended (the “Plan”);WHEREAS, pursuant to Section 5.2 of the Plan, the Compensation Committee of the Board of Directors of the Company (the “Committee”) isauthorized to amend the Plan to the extent that the Committee deems such amendment advisable, subject to certain requirements; andWHEREAS, the Committee has approved the adoption of this amendment, in order to allow flexibility with respect to the approval of permittedawards to executives who are not officers subject to Section 16 of the Securities Exchange Act of 1934, as amended.NOW, THEREFORE, the Plan is amended for all outstanding and future awards under the Plan, effective October 26, 2015, as follows:1. The second paragraph of Section 1.3 of the Plan is amended by deleting the phrase “or whose title with the Company is ‘executive vice president’ orhigher” therein.IN WITNESS WHEREOF, the Company has caused this amendment to be executed this 18th day of December, 2015. Exelon CorporationBy: /s/ Amy BestAmy BestSenior Vice President &Chief Human Resources OfficerSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 3,952 1,798 2,773 2,486 3,330 Plus: Loss from equity investees 1 91 (10) 20 — Less: Capitalized interest (57) (75) (67) (79) (99) Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest 3,896 1,814 2,696 2,427 3,231 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 761 1,021 1,436 1,110 1,107 Interest component of rental expense (a) 237 310 269 288 300 Total fixed charges 998 1,331 1,705 1,398 1,407 Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest plus fixed charges 4,894 3,145 4,401 3,825 4,638 Ratio of earnings to fixed charges 4.9 2.4 2.6 2.7 3.3 (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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 3,952 1,798 2,773 2,486 3,330 Plus: Loss from equity investees 1 91 (10) 20 — Less: Capitalized interest (57) (75) (67) (79) (99) Preference security dividend requirements (6) (26) (32) (18) (19) Pre-tax income from continuing operations after adjustment for income or loss from equity investees,capitalized interest and preference security dividend requirements 3,890 1,788 2,664 2,409 3,212 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 761 1,021 1,436 1,110 1,107 Interest component of rental expense (a) 237 310 269 288 300 Preference security dividend requirements of consolidated subsidiaries 6 26 32 18 19 Total fixed charges 1,004 1,357 1,737 1,416 1,426 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 4,894 3,145 4,401 3,825 4,638 Ratio of earnings to fixed charges and preferred stock dividends 4.9 2.3 2.5 2.7 3.3 (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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 2,827 1,058 1,675 1,226 1,850 Plus: (Income) or loss from equity investees 1 91 (10) 20 — Less: Capitalized interest (49) (67) (54) (63) (79) Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest 2,779 1,082 1,611 1,183 1,771 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 219 402 445 396 427 Interest component of rental expense (a) 220 291 248 269 284 Total fixed charges 439 693 693 665 711 Pre-tax income from continuing operations after adjustment for income or loss from equity investees andcapitalized interest plus fixed charges 3,218 1,775 2,304 1,848 2,482 Ratio of earnings to combined fixed charges 7.3 2.6 3.3 2.8 3.5 (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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 666 618 401 676 706 Plus: Loss from equity investees — — — — Less:Capitalized interest (4) (3) (5) (2) (4) Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalizedinterest 662 615 396 674 702 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 330 297 575 311 331 Interest component of rental expense (a) 6 6 5 5 4 Total fixed charges 336 303 580 316 335 Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalizedinterest plus fixed charges 998 918 976 990 1,037 Ratio of earnings to fixed charges 3.0 3.0 1.7 3.1 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 535 508 557 466 521 Plus: Loss from equity investees — — — — — Less: Capitalized interest (4) (2) (2) (2) (2) Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalizedinterest 531 506 555 464 519 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 135 122 114 112 114 Interest component of rental expense (a) 9 9 7 5 3 Total fixed charges 144 131 121 117 117 Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalizedinterest plus fixed charges 675 637 676 581 636 Ratio of earnings to combined fixed charges 4.7 4.9 5.6 5.0 5.4 (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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 535 508 557 466 521 Plus: Loss from equity investees — — — — — Less: Capitalized interest (4) (2) (2) (2) (2) Preference security dividend requirements (6) (5) (10) — — Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interestand preference security dividend requirements 525 501 545 464 519 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 135 122 114 112 114 Interest component of rental expense (a) 9 9 7 5 3 Preference security dividend requirements 6 5 10 — — Total fixed charges 150 136 131 117 117 Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interestand preference security dividend requirements plus fixed charges 675 637 676 581 636 Ratio of earnings to fixed charges and preferred stock dividends 4.5 4.7 5.2 5.0 5.4 (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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 211 11 344 351 477 Less: Capitalized interest (7) (5) (6) (12) (14) Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalizedinterest 204 6 338 339 463 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 136 149 127 118 113 Interest component of rental expense (a) 5 4 4 4 11 Total fixed charges 141 153 131 122 124 Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interestand preference security dividend requirements plus fixed charges 345 159 469 461 587 Ratio of earnings to fixed charges 2.4 1.0 3.6 3.8 4.7 (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, 2011 2012 2013 2014 2015 Pre-tax income from continuing operations 211 11 344 351 477 Less: Capitalized interest (7) (5) (6) (12) (14) Preference security dividend requirements (20) (20) (21) (22) (22) Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalizedinterest 184 (14) 317 317 441 Fixed Charges: Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness 136 149 127 118 113 Interest component of rental expense (a) 5 4 4 4 11 Preference security dividend requirements 20 20 21 22 22 Total fixed charges 161 173 152 144 146 Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalizedinterest and preference security dividend requirements plus fixed charges 345 159 469 461 587 Ratio of earnings to fixed charges and preferred stock dividends 2.1 0.9 (b) 3.1 3.2 4.0 (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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Corporation12/31/2015 Name Jurisdiction2014 ESA HoldCo, LLC Delaware2014 ESA Project Company, LLC Delaware2015 ESA Holdco, LLC Delaware2015 ESA Investco, LLC Delaware2015 ESA Project Company, LLC DelawareAgriWind LLC IllinoisAgriWind Project L.L.C. DelawareAlbany Green Energy, LLC GeorgiaAnnova LNG Brownsville A, LLC DelawareAnnova LNG Brownsville B, LLC DelawareAnnova LNG Brownsville C, LLC DelawareAnnova LNG Common Infrastructure, LLC DelawareAnnova LNG, LLC DelawareAnnova LNG, LLC, Series A Units DelawareAnnova LNG, LLC, Series B Units DelawareAnnova LNG, LLC, Series C Units DelawareAnnova LNG, LLC, Series Z Units 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. MinnesotaBluestem Wind Energy, LLC DelawareBraidwood 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 NevadaCalifornia PV Energy 2, LLC 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 Colver I, Inc. MarylandCE Colver III, Inc. MarylandCE Culm, Inc. MarylandCE FundingCo, LLC DelawareCE Nuclear, LLC DelawareCECG International Holdings, Inc. DelawareCER Generation, LLC DelawareCEU Arkoma West, LLC DelawareCEU CHC, LLC DelawareCEU CoLa, LLC DelawareCEU Development, LLC DelawareCEU East Fort Peck, LLC DelawareCEU Fayetteville, LLC DelawareCEU Floyd Shale, LLC DelawareCEU Holdings, LLC DelawareCEU Huntsville, LLC DelawareCEU Kingston, LLC DelawareCEU Niobrara, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 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 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 Bulk Energy Holdings, Inc. Marshall IslandsConstellation CNG, LLC DelawareConstellation DCO Albany Power Holdings, LLC DelawareConstellation EG, 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 Services - Natural Gas, LLC DelawareConstellation Energy Services of New York, Inc. New YorkConstellation Energy Services, Inc. WisconsinConstellation Energy Upstream Holdings, Inc. DelawareConstellation Holdings, LLC MarylandConstellation International Holdings, Inc. Marshall IslandsConstellation Mystic Power, LLC DelawareConstellation NewEnergy - Gas Division, LLC KentuckyConstellation NewEnergy Canada Inc. OntarioConstellation NewEnergy, Inc. DelawareConstellation Nuclear Power Plants, LLC DelawareConstellation Nuclear, LLC DelawareConstellation Operating Services CaliforniaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Source Generation, LLC MarylandConstellation Power, Inc. MarylandConstellation Sacramento Holding, LLC DelawareConstellation Solar Arizona 2, LLC DelawareConstellation Solar Arizona, LLC DelawareConstellation Solar California, LLC DelawareConstellation Solar Connecticut, LLC DelawareConstellation Solar DC, LLC DelawareConstellation Solar Federal, LLC DelawareConstellation Solar Georgia, LLC GeorgiaConstellation Solar Holding, LLC DelawareConstellation Solar Horizons Holding, LLC DelawareConstellation Solar Horizons, LLC DelawareConstellation Solar Maryland II, LLC DelawareConstellation Solar Maryland MC, LLC DelawareConstellation Solar Maryland, LLC DelawareConstellation Solar Massachusetts, LLC DelawareConstellation Solar Net Metering, LLC DelawareConstellation Solar New Jersey II, LLC DelawareConstellation Solar New Jersey III, LLC DelawareConstellation Solar New Jersey, LLC DelawareConstellation Solar New York, LLC DelawareConstellation Solar Ohio, LLC DelawareConstellation Solar, LLC DelawareContinental Wind Holding, LLC DelawareContinental Wind, LLC 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, LLC MinnesotaCR Clearing, LLC MissouriCriterion Power Partners, LLC DelawareDAJAW Transmission LLC MinnesotaDenver Airport Solar, LLC DelawareDresden 1 NQF, LLC NevadaDresden 2 NQF, LLC NevadaDresden 3 NQF, LLC NevadaEnergy Performance Services, Inc. PennsylvaniaETT Canada, Inc. New BrunswickEwington Energy Systems LLC MinnesotaExelon AVSR Holding, LLC DelawareExelon AVSR, LLC DelawareExelon Business Services Company, LLC DelawareExelon Corporation PennsylvaniaExelon Energy Delivery Company, LLC DelawareExelon Enterprises Company, LLC PennsylvaniaExelon Framingham, LLC DelawareExelon Fulton, LLC DelawareExelon Generation Acquisitions, LLC DelawareExelon Generation Company, LLC PennsylvaniaExelon Generation Consolidation, LLC NevadaExelon Generation Finance Company, LLC DelawareExelon Generation International, Inc. PennsylvaniaExelon Generation Limited United KingdomExelon Mechanical, LLC DelawareExelon Microgrid, LLC DelawareExelon New Boston, LLC DelawareExelon New England Holdings, LLC DelawareExelon Nuclear Partners International S.a r.l. LuxembourgExelon Nuclear Partners, LLC DelawareExelon Nuclear Security, LLC DelawareExelon Peaker Development Limited, LLC DelawareExelon PowerLabs, LLC PennsylvaniaExelon Solar Chicago LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Transmission Company, LLC DelawareExelon West Medway II, LLC DelawareExelon West Medway, LLC DelawareExelon Wind 1, LLC TexasExelon Wind 10, LLC TexasExelon Wind 11, LLC TexasExelon Wind 2, LLC TexasExelon Wind 3, LLC TexasExelon Wind 4, LLC TexasExelon Wind 5, LLC TexasExelon Wind 6, LLC TexasExelon Wind 7, LLC TexasExelon Wind 8, LLC TexasExelon Wind 9, LLC TexasExelon Wind Canada Inc. CanadaExelon Wind, LLC DelawareExelon Wyman, LLC DelawareEx-FM, Inc. New YorkEx-FME, Inc. DelawareExGen Renewables Holdings II, LLC DelawareExGen Renewables I Holding, LLC DelawareExGen Renewables I, LLC DelawareExGen Renewables II, LLC DelawareExGen Texas II Power Holdings, LLC DelawareExGen Texas II Power, LLC DelawareExGen Texas Power Holdings, LLC DelawareExGen Texas Power Services, LLC DelawareExGen Texas Power, LLC DelawareExGen Ventures International Holdings II Limited United KingdomExGen Ventures International Holdings Limited United KingdomExTel Corporation, LLC DelawareF & M Holdings Company, L.L.C. DelawareFair Wind Power Partners, LLC DelawareFour Corners Windfarm, LLC OregonFour Mile Canyon Windfarm, LLC OregonFourmile Wind Energy, LLC MarylandG-Flow Wind, LLC MinnesotaGrande Prairie Generation, Inc. AlbertaGreen Acres Breeze, LLC MinnesotaGreensburg Wind Farm, LLC DelawareHandley Power, LLC DelawareHandsome Lake Energy, LLC MarylandHarvest II Windfarm, LLC DelawareHarvest Windfarm, LLC MichiganHigh Mesa Energy, LLC IdahoHigh Plains Wind Power, LLC TexasHolyoke Solar, LLC DelawareHot Springs Windfarm, LLC IdahoK & D Energy LLC MinnesotaKC Energy LLC MinnesotaKSS Turbines LLC MinnesotaLa Salle 1 NQF, LLC NevadaLa Salle 2 NQF, LLC NevadaLake Houston Power, LLC DelawareLaPorte Power, LLC DelawareLas Vegas District Energy, LLC DelawareLimerick 1 NQF, LLC NevadaLimerick 2 NQF, LLC NevadaLoess Hills Wind Farm, LLC MissouriMarshall Wind 1, LLC MinnesotaMarshall Wind 2, LLC MinnesotaMarshall Wind 3, LLC MinnesotaMarshall Wind 4, LLC MinnesotaMarshall Wind 5, LLC MinnesotaMarshall Wind 6, LLC MinnesotaMichigan Wind 1, LLC DelawareMichigan Wind 2, LLC DelawareMichigan Wind 3, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Minergy LLC WisconsinMinnesota Breeze, LLC MinnesotaMohave Sunrise Solar I, LLC ArizonaMountain Creek Power, LLC DelawareMountain Top Wind Power, LLC MarylandNine Mile Point Nuclear Station, LLC DelawareNorth Shore District Energy, LLC DelawareNorthwind Thermal Technologies Canada Inc. New BrunswickOMF 11520, LLC DelawareOregon Trail Windfarm, LLC OregonOutback Solar, LLC OregonOyster Creek NQF, LLC NevadaPacific Canyon Windfarm, LLC OregonPanther Creek Holdings, Inc. DelawarePanther Creek Partners DelawarePeach Bottom 1 NQF, LLC NevadaPeach Bottom 2 NQF, LLC NevadaPeach Bottom 3 NQF, LLC NevadaPEC Financial Services, LLC PennsylvaniaPECO Energy Capital Corp. DelawarePECO Energy Capital Trust III DelawarePECO Energy Capital Trust IV DelawarePECO Energy Capital, L.P. DelawarePECO Energy Company PennsylvaniaPECO Wireless, LLC DelawarePegasus Power Company, Inc. CaliforniaPH Holdco LLC DelawarePinedale Energy, LLC ColoradoPrairie Wind Power LLC MinnesotaPurple Acquisition Corp. DelawareQuad Cities 1 NQF, LLC NevadaQuad Cities 2 NQF, LLC NevadaR.E. Ginna Nuclear Power Plant, LLC MarylandRenewable Power Generation Holdings, LLC DelawareRenewable Power Generation, LLC DelawareResidential Solar Holding, LLC DelawareResidential Solar II, LLC DelawareRF HoldCo LLC DelawareRITELine Illinois, LLC IllinoisRITELine Indiana, LLC IndianaRITELine Transmission Development, LLC DelawareRoadrunner-I LLC MinnesotaRSB BondCo LLC DelawareSacramento PV Energy, LLC DelawareSalem 1 NQF, LLC NevadaSalem 2 NQF, LLC NevadaSalty Dog-I LLC MinnesotaSalty Dog-II LLC MinnesotaSand Ranch Windfarm, LLC OregonScherer Holdings 1, LLC DelawareScherer Holdings 2, LLC DelawareScherer Holdings 3, LLC DelawareSendero Wind Energy, LLC DelawareShane’s Wind Machine LLC MinnesotaShooting Star Wind Project, LLC DelawareSky Valley, LLC DelawareStar Electricity, Inc. TexasSugar Beet Wind, LLC DelawareSunnyside Cogeneration Associates UtahSunnyside Generation, LLC DelawareSunnyside II, Inc. DelawareSunnyside II, L.P. DelawareSunnyside III, Inc. DelawareSunnyside Properties, LLC UtahSunset Breeze, LLC MinnesotaThreemile Canyon Wind I, LLC OregonTitan STC, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, LLC NevadaTuana Springs Energy, LLC IdahoUII, LLC IllinoisW&D Gas Partners, LLC DelawareWagon Trail, LLC OregonWally’s Wind Farm LLC MinnesotaWansley Holdings 1, LLC DelawareWansley Holdings 2, LLC DelawareWard Butte Windfarm, LLC OregonWater & Energy Savings Company, LLC DelawareWestern Path Development, LLC DelawareWhitetail Wind Energy, LLC DelawareWibaux Wind, LLC DelawareWildcat Finance, LLC DelawareWildcat Wind LLC New MexicoWind Capital Holdings, LLC MissouriWindy Dog-1 LLC MinnesotaWolf Hollow I Power, LLC DelawareWolf Hollow II Power, LLC DelawareWolf Hollow Services, LLC DelawareWolf Wind Enterprises, LLC MinnesotaWolf Wind Transmission, LLC MinnesotaZion 1 NQF, LLC NevadaZion 2 NQF, LLC Nevada Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, LLC12/31/2015 Name Jurisdiction2014 ESA HoldCo, LLC Delaware2014 ESA Project Company, LLC Delaware2015 ESA Holdco, LLC Delaware2015 ESA Investco, LLC Delaware2015 ESA Project Company, LLC DelawareAgriWind LLC IllinoisAgriWind Project L.L.C. DelawareAlbany Green Energy, LLC GeorgiaAnnova LNG Brownsville A, LLC DelawareAnnova LNG Brownsville B, LLC DelawareAnnova LNG Brownsville C, LLC DelawareAnnova LNG Common Infrastructure, LLC DelawareAnnova LNG, LLC DelawareAnnova LNG, LLC, Series A Units DelawareAnnova LNG, LLC, Series B Units DelawareAnnova LNG, LLC, Series C Units DelawareAnnova LNG, LLC, Series Z Units 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. MinnesotaBluestem Wind Energy, LLC DelawareBraidwood 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 NevadaCalifornia PV Energy 2, LLC 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 Colver I, Inc. MarylandCE Colver III, Inc. MarylandCE Culm, Inc. MarylandCE FundingCo, LLC DelawareCE Nuclear, LLC DelawareCECG International Holdings, Inc. DelawareCER Generation, LLC DelawareCEU Arkoma West, LLC DelawareCEU CHC, LLC DelawareCEU CoLa, LLC DelawareCEU Development, LLC DelawareCEU East Fort Peck, LLC DelawareCEU Fayetteville, LLC DelawareCEU Floyd Shale, LLC DelawareCEU Holdings, LLC DelawareCEU Huntsville, LLC DelawareCEU Kingston, LLC DelawareCEU Niobrara, LLC DelawareCEU Offshore I, LLC DelawareCEU Ohio Shale, LLC DelawareCEU Paradigm, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Pinedale, LLC DelawareCEU Plymouth, LLC DelawareCEU Simplicity, LLC DelawareCEU Trenton, LLC DelawareCEU W&D, LLC 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 DelawareCompass Energy Gas Services, LLC VirginiaCompass Energy Services, Inc. VirginiaConstellation Bulk Energy Holdings, Inc. Marshall IslandsConstellation CNG, LLC DelawareConstellation DCO Albany Power Holdings, LLC DelawareConstellation EG, 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 Services - Natural Gas, LLC DelawareConstellation Energy Services of New York, Inc. New YorkConstellation Energy Services, Inc. WisconsinConstellation Energy Upstream Holdings, Inc. DelawareConstellation Holdings, LLC MarylandConstellation International Holdings, Inc. Marshall IslandsConstellation Mystic Power, LLC DelawareConstellation NewEnergy - Gas Division, LLC KentuckyConstellation NewEnergy Canada Inc. OntarioConstellation NewEnergy, Inc. DelawareConstellation Nuclear Power Plants, LLC DelawareConstellation Nuclear, LLC DelawareConstellation Operating Services CaliforniaConstellation Power Source Generation, LLC MarylandConstellation Power, Inc. MarylandConstellation Sacramento Holding, LLC DelawareConstellation Solar Arizona 2, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Solar Arizona, LLC DelawareConstellation Solar California, LLC DelawareConstellation Solar Connecticut, LLC DelawareConstellation Solar DC, LLC DelawareConstellation Solar Federal, LLC DelawareConstellation Solar Georgia, LLC GeorgiaConstellation Solar Holding, LLC DelawareConstellation Solar Horizons Holding, LLC DelawareConstellation Solar Horizons, LLC DelawareConstellation Solar Maryland II, LLC DelawareConstellation Solar Maryland MC, LLC DelawareConstellation Solar Maryland, LLC DelawareConstellation Solar Massachusetts, LLC DelawareConstellation Solar Net Metering, LLC DelawareConstellation Solar New Jersey II, LLC DelawareConstellation Solar New Jersey III, LLC DelawareConstellation Solar New Jersey, LLC DelawareConstellation Solar New York, LLC DelawareConstellation Solar Ohio, LLC DelawareConstellation Solar, LLC DelawareContinental Wind Holding, LLC DelawareContinental Wind, LLC 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, LLC MinnesotaCR Clearing, LLC MissouriCriterion Power Partners, LLC DelawareDAJAW Transmission LLC MinnesotaDenver Airport Solar, LLC DelawareDresden 1 NQF, LLC NevadaDresden 2 NQF, LLC NevadaDresden 3 NQF, LLC NevadaEnergy Performance Services, Inc. PennsylvaniaEwington Energy Systems LLC MinnesotaExelon AVSR Holding, LLC DelawareExelon AVSR, LLC DelawareExelon Framingham, LLC DelawareExelon Fulton, LLC DelawareExelon Generation Acquisitions, LLC DelawareExelon Generation Company, LLC PennsylvaniaExelon Generation Consolidation, LLC NevadaExelon Generation Finance Company, LLC DelawareExelon Generation International, Inc. PennsylvaniaExelon Generation Limited United KingdomExelon New Boston, LLC DelawareExelon New England Holdings, LLC DelawareExelon Nuclear Partners International S.a r.l. LuxembourgExelon Nuclear Partners, LLC DelawareExelon Nuclear Security, LLC DelawareExelon Peaker Development Limited, LLC DelawareExelon PowerLabs, LLC PennsylvaniaExelon Solar Chicago LLC DelawareExelon West Medway II, LLC DelawareExelon West Medway, LLC DelawareExelon Wind 1, LLC TexasExelon Wind 10, LLC TexasExelon Wind 11, LLC TexasExelon Wind 2, LLC TexasExelon Wind 3, LLC TexasExelon Wind 4, LLC TexasExelon Wind 5, LLC TexasExelon Wind 6, LLC TexasSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Wind 7, LLC TexasExelon Wind 8, LLC TexasExelon Wind 9, LLC TexasExelon Wind Canada Inc. CanadaExelon Wind, LLC DelawareExelon Wyman, LLC DelawareExGen Renewables Holdings II, LLC DelawareExGen Renewables I Holding, LLC DelawareExGen Renewables I, LLC DelawareExGen Renewables II, LLC DelawareExGen Texas II Power Holdings, LLC DelawareExGen Texas II Power, LLC DelawareExGen Texas Power Holdings, LLC DelawareExGen Texas Power Services, LLC DelawareExGen Texas Power, LLC DelawareExGen Ventures International Holdings II Limited United KingdomExGen Ventures International Holdings Limited United KingdomFair Wind Power Partners, LLC DelawareFour Corners Windfarm, LLC OregonFour Mile Canyon Windfarm, LLC OregonFourmile Wind Energy, LLC MarylandG-Flow Wind, LLC MinnesotaGrande Prairie Generation, Inc. AlbertaGreen Acres Breeze, LLC MinnesotaGreensburg Wind Farm, LLC DelawareHandley Power, LLC DelawareHandsome Lake Energy, LLC MarylandHarvest II Windfarm, LLC DelawareHarvest Windfarm, LLC MichiganHigh Mesa Energy, LLC IdahoHigh Plains Wind Power, LLC TexasHolyoke Solar, LLC DelawareHot Springs Windfarm, LLC IdahoK & D Energy LLC MinnesotaKC Energy LLC MinnesotaKSS Turbines LLC MinnesotaLa Salle 1 NQF, LLC NevadaLa Salle 2 NQF, LLC NevadaLake Houston Power, LLC DelawareLaPorte Power, LLC DelawareLas Vegas District Energy, LLC DelawareLimerick 1 NQF, LLC NevadaLimerick 2 NQF, LLC NevadaLoess Hills Wind Farm, LLC MissouriMarshall Wind 1, LLC MinnesotaMarshall Wind 2, LLC MinnesotaMarshall Wind 3, LLC MinnesotaMarshall Wind 4, LLC MinnesotaMarshall Wind 5, LLC MinnesotaMarshall Wind 6, LLC MinnesotaMichigan Wind 1, LLC DelawareMichigan Wind 2, LLC DelawareMichigan Wind 3, LLC DelawareMinergy LLC WisconsinMinnesota Breeze, LLC MinnesotaMohave Sunrise Solar I, LLC ArizonaMountain Creek Power, LLC DelawareMountain Top Wind Power, LLC MarylandNine Mile Point Nuclear Station, LLC DelawareNorth Shore District Energy, LLC DelawareOregon Trail Windfarm, LLC OregonOutback Solar, LLC OregonOyster Creek NQF, LLC NevadaPacific Canyon Windfarm, LLC OregonPanther Creek Holdings, Inc. DelawarePanther Creek Partners DelawarePeach Bottom 1 NQF, LLC NevadaPeach Bottom 2 NQF, LLC NevadaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.Peach Bottom 3 NQF, LLC NevadaPegasus Power Company, Inc. CaliforniaPinedale Energy, LLC ColoradoPrairie Wind Power LLC MinnesotaQuad Cities 1 NQF, LLC NevadaQuad Cities 2 NQF, LLC NevadaR.E. Ginna Nuclear Power Plant, LLC MarylandRenewable Power Generation Holdings, LLC DelawareRenewable Power Generation, LLC DelawareResidential Solar Holding, LLC DelawareResidential Solar II, LLC DelawareRoadrunner-I LLC MinnesotaSacramento PV Energy, LLC DelawareSalem 1 NQF, LLC NevadaSalem 2 NQF, LLC NevadaSalty Dog-I LLC MinnesotaSalty Dog-II LLC MinnesotaSand Ranch Windfarm, LLC OregonSendero Wind Energy, LLC DelawareShane’s Wind Machine LLC MinnesotaShooting Star Wind Project, LLC DelawareSky Valley, LLC DelawareStar Electricity, Inc. TexasSugar Beet Wind, LLC DelawareSunnyside Cogeneration Associates UtahSunnyside Generation, LLC DelawareSunnyside II, Inc. DelawareSunnyside II, L.P. DelawareSunnyside III, Inc. DelawareSunnyside Properties, LLC UtahSunset Breeze, LLC MinnesotaThreemile Canyon Wind I, LLC OregonTitan STC, LLC DelawareTMI NQF, LLC NevadaTuana Springs Energy, LLC IdahoW&D Gas Partners, LLC DelawareWagon Trail, LLC OregonWally’s Wind Farm LLC MinnesotaWard Butte Windfarm, LLC OregonWater & Energy Savings Company, LLC DelawareWhitetail Wind Energy, LLC DelawareWibaux Wind, LLC DelawareWildcat Finance, LLC DelawareWildcat Wind LLC New MexicoWind Capital Holdings, LLC MissouriWindy Dog-1 LLC MinnesotaWolf Hollow I Power, LLC DelawareWolf Hollow II Power, LLC DelawareWolf Hollow Services, LLC DelawareWolf Wind Enterprises, LLC MinnesotaWolf Wind Transmission, LLC MinnesotaZion 1 NQF, LLC NevadaZion 2 NQF, LLC NevadaSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 21.3Commonwealth Edison Company Subsidiary JurisdictionComEd Financing III DelawareCommonwealth Edison Company of Indiana, Inc. IndianaRITELine Illinois, LLC IllinoisSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 Company12/31/2015 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 Wireless, LLC DelawareSource: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. 333-196220 and No. 333-206474), Form S-4 (No. 333-209209) and on Form S-8 (No.333-189849, No.333-175162, No.333-127377, No.333-37082, No.333-49780 and No. 333-61390) of Exelon Corporation ofour report dated February 10, 2016 relating to the financial statements, financial statement schedules and the effectiveness of internal control over financialreporting of Exelon Corporation, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLPChicago, IllinoisFebruary 10, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016 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 10, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016 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 10, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016 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 10, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016 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 10, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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. Anderson DATE: February 8, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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. Berzin DATE: February 8, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 4, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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. Crane DATE: February 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 Balmann DATE: February 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 DeBenedictis DATE: February 4, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 JoskowPaul JoskowDATE: February 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 24-8POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Linda P. Jojo, 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 2015 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/ Linda P. JojoLinda P. JojoDATE: February 3, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 3, 2016 Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 9, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 3, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 4, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 4, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 4, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 3, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 3, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 24-23POWER 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 2015 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 4, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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 2015 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 4, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, Nelson A. Diaz, 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 2015 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/ Nelson A. DiazNelson A. DiazDATE: February 8, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 24-28POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Rosemarie B. Greco, 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 2015 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/ Rosemarie B. GrecoRosemarie B. GrecoDATE: February 6, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 24-29POWER OF ATTORNEYKNOW ALL MEN BY THESE PRESENTS that I, Charisse R. Lillie, 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 2015 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/ Charisse R. LillieCharisse R. LillieDATE: February 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 8, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 2, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 5, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 9, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 2015 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 3, 2016Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ CHRISTOPHER M. CRANEPresident and Chief Executive Officer(Principal Executive Officer) Date: February 10, 2016 481Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ JONATHAN W. THAYERSenior Executive Vice President and Chief Financial Officer(Principal Financial Officer) Date: February 10, 2016 482Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ KENNETH W. CORNEWPresident and Chief Executive Officer(Principal Executive Officer) Date: February 10, 2016 483Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ BRYAN P. WRIGHTSenior Vice President and Chief Financial Officer(Principal Financial Officer) Date: February 10, 2016 484Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ ANNE R. PRAMAGGIOREPresident and Chief Executive Officer(Principal Executive Officer) Date: February 10, 2016 485Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ JOSEPH R. TRPIK, JR.Senior Vice President, Chief Financial Officer and Treasurer(Principal Financial Officer) Date: February 10, 2016 486Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ CRAIG L. ADAMSPresident and Chief Executive Officer(Principal Executive Officer) Date: February 10, 2016 487Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ PHILLIP S. BARNETTSenior Vice President, Chief Financial Officer and Treasurer(Principal Financial Officer) Date: February 10, 2016 488Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 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. /S/ CALVIN G. BUTLERChief Executive Officer(Principal Executive Officer) Date: February 10, 2016 489Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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. /S/ DAVID M. VAHOSVice President, Chief Financial Officer and Treasurer(Principal Financial Officer) Date: February 10, 2016 490Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ CHRISTOPHER M. CRANEChristopher M. CranePresident and Chief Executive Officer Date: February 10, 2016 491Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ JONATHAN W. THAYERJonathan W. ThayerSenior Executive Vice President and Chief Financial Officer Date: February 10, 2016 492Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ KENNETH W. CORNEWKenneth W. CornewPresident and Chief Executive Officer Date: February 10, 2016 493Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ BRYAN P. WRIGHTBryan P. WrightSenior Vice President and Chief Financial Officer Date: February 10, 2016 494Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ ANNE R. PRAMAGGIOREAnne R. PramaggiorePresident and Chief Executive Officer Date: February 10, 2016 495Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ JOSEPH R. TRPIK, JR.Joseph R. Trpik, Jr.Senior Vice President, Chief Financial Officer and Treasurer Date: February 10, 2016 496Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015,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. /S/ CRAIG L. ADAMSCraig L. AdamsPresident and Chief Executive Officer Date: February 10, 2016 497Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015,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. /S/ PHILLIP S. BARNETTPhillip S. BarnettSenior Vice President, Chief Financial Officer and Treasurer Date: February 10, 2016 498Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ CALVIN G. BUTLER, JR.Calvin G. Butler, Jr.Chief Executive Officer Date: February 10, 2016 499Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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, 2015, 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. /S/ DAVID M. VAHOSDavid M. VahosVice President, Chief Financial Officer and Treasurer Date: February 10, 2016 500Source: BALTIMORE GAS & ELECTRIC CO, 10-K, February 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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 10, 2016Powered by Morningstar® Document Research℠The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this information,except 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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