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EXC Exelon

Filed: 24 Feb 21, 3:10pm
December 31, 20202020FY--12-31976,337,79935,402,501,369127,021,370170,478,5071,0001001,0008,546,017000110935700011681650000022606000007810000000094660001135971000007973200000278790000008192FALSEPA10 South Dearborn StreetP.O. Box 805379ChicagoIL60680-5379(800)483-3220PA300 Exelon WayKennett SquarePA19348-2473(610)765-5959IL440 South LaSalle StreetChicagoIL60605-1028(312)394-4321PAP.O. Box 86992301 Market StreetPhiladelphiaPA19101-8699(215)841-4000MD2 Center Plaza110 West Fayette StreetBaltimoreMD21201-3708(410)234-5000DE701 Ninth Street, N.W.Washington, District of Columbia20068(202)872-2000DCVA701 Ninth Street, N.W.Washington, District of Columbia20068(202)872-2000DEVA500 North Wakefield DriveNewarkDE19702(202)872-2000NJ500 North Wakefield DriveNewarkDE19702(202)872-2000Common Stock, without par valueEXCNasdaqEXC/28NYSECumulative Preferred Security, Series D,0015001500100010001001001,0001,0001,0001,00058015858047518150158181105803350570570555505805804502050575575575350575255057057557585056513155005005001111111112 years2 years5 years3 years5 years3 years5 years1 years1 years2 years1 years853541385111111730 years30 years5 years30 years5 years30 years5 years12 years4 years2 years1 years10.110.53.84.28.38.29.19.14.010.110.64.64.45.49.09.89.74.76.56.36.56.5111122111111 years1 years5 years5 years5 years823116822212512179 years5 years79 years50 years5 years2034-12-312034-12-312032-12-312033-12-312029-12-312029-12-312032-12-312031-12-312034-12-312034-12-312021-12-312021-12-312029-12-310.6501.65000.2750.2750000.07500.0750.901.2751.2751.000.900.901.0751.001.0750.002750.012750.3750.3750000000000000000000000000000P3Y0001109357exc:SmallCommercialIndustrialMemberus-gaap:RegulatedOperationMemberus-gaap:ElectricityUsRegulatedMemberexc:PecoEnergyCoMember2019-01-012019-12-310001109357exc:AtlanticCityElectricCompanyMemberus-gaap:StateAndLocalJurisdictionMember2018-01-012018-12-310001109357us-gaap:FairValueInputsLevel1Memberus-gaap:ForeignGovernmentDebtSecuritiesMemberus-gaap:FairValueMeasurementsRecurringMember2020-12-310001109357exc:BaltimoreGasAndElectricCompanyMembersrt:ParentCompanyMember2020-12-31

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2020
 or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number
Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone NumberIRS Employer Identification Number
001-16169EXELON CORPORATION23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
333-85496EXELON GENERATION COMPANY, LLC23-3064219
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
001-01839COMMONWEALTH EDISON COMPANY36-0938600
(an Illinois corporation)
440 South LaSalle Street
Chicago, Illinois 60605-1028
(312) 394-4321
000-16844PECO ENERGY COMPANY23-0970240
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
001-01910BALTIMORE GAS AND ELECTRIC COMPANY52-0280210
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
001-31403PEPCO HOLDINGS LLC52-2297449
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
001-01072POTOMAC ELECTRIC POWER COMPANY53-0127880
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
001-01405DELMARVA POWER & LIGHT COMPANY51-0084283
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
001-03559ATLANTIC CITY ELECTRIC COMPANY21-0398280
(a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000



Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
EXELON CORPORATION:
Common Stock, without par valueEXCThe Nasdaq Stock Market LLC
PECO ENERGY COMPANY:
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy CompanyEXC/28New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants (1971 Warrants and Series B Warrants)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Exelon CorporationYesxNo
Exelon Generation Company, LLCYesNox
Commonwealth Edison CompanyYesNox
PECO Energy CompanyYesNox
Baltimore Gas and Electric CompanyYesNox
Pepco Holdings LLCYesNox
Potomac Electric Power CompanyYesNox
Delmarva Power & Light CompanyYesNox
Atlantic City Electric CompanyYesNox
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 CorporationYesNox
Exelon Generation Company, LLCYesNox
Commonwealth Edison CompanyYesNox
PECO Energy CompanyYesNox
Baltimore Gas and Electric CompanyYesNox
Pepco Holdings LLCYesNox
Potomac Electric Power CompanyYesNox
Delmarva Power & Light CompanyYesNox
Atlantic City Electric CompanyYesNox
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨



Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Exelon CorporationLarge Accelerated FilerxAccelerated FilerNon-accelerated FilerSmaller Reporting CompanyEmerging Growth Company
Exelon Generation Company, LLCLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
Commonwealth Edison CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
PECO Energy CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
Baltimore Gas and Electric CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
Pepco Holdings LLCLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
Potomac Electric Power CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
Delmarva Power & Light CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
Atlantic City Electric CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerxSmaller Reporting CompanyEmerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act by the registered public accounting firm that prepared or issued its audit report. x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  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, 2020 was as follows:
Exelon Corporation Common Stock, without par value$35,402,501,369
Exelon Generation Company, LLCNot applicable
Commonwealth Edison Company Common Stock, $12.50 par valueNo established market
PECO Energy Company Common Stock, without par valueNone
Baltimore Gas and Electric Company, without par valueNone
Pepco Holdings LLCNot applicable
Potomac Electric Power CompanyNone
Delmarva Power & Light CompanyNone
Atlantic City Electric CompanyNone
The number of shares outstanding of each registrant’s common stock as of January 31, 2021 was as follows:
Exelon Corporation Common Stock, without par value976,337,799 
Exelon Generation Company, LLCNot applicable
Commonwealth Edison Company Common Stock, $12.50 par value127,021,370 
PECO Energy Company Common Stock, without par value170,478,507 
Baltimore Gas and Electric Company Common Stock, without par value1,000 
Pepco Holdings LLCNot applicable
Potomac Electric Power Company Common Stock, $0.01 par value100 
Delmarva Power & Light Company Common Stock, $2.25 par value1,000 
Atlantic City Electric Company Common Stock, $3.00 par value8,546,017 
Documents Incorporated by Reference

Portions of the Exelon Proxy Statement for the 2020 Annual Meeting of Shareholders and the Commonwealth Edison Company 2020 Information Statement are incorporated by reference in Part III.

Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the reduced disclosure format.



TABLE OF CONTENTS











GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
ExelonExelon Corporation
GenerationExelon Generation Company, LLC
ComEdCommonwealth Edison Company
PECOPECO Energy Company
BGEBaltimore Gas and Electric Company
Pepco Holdings or PHI  Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco  Potomac Electric Power Company
DPL  Delmarva Power & Light Company
ACE  Atlantic City Electric Company
RegistrantsExelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility RegistrantsComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
Legacy PHIPHI, Pepco, DPL, ACE, PES, and PCI, collectively
ACE Funding or ATF  Atlantic City Electric Transition Funding LLC
Antelope ValleyAntelope Valley Solar Ranch One
BondCoRSB BondCo LLC
BSCExelon Business Services Company, LLC
CENGConstellation Energy Nuclear Group, LLC
ConstellationConstellation Energy Group, Inc.
EEDCExelon Energy Delivery Company, LLC
EGR IVExGen Renewables IV, LLC
EGRPExGen Renewables Partners, LLC
Exelon CorporateExelon in its corporate capacity as a holding company
Exelon Transmission CompanyExelon Transmission Company, LLC
FitzPatrickJames A. FitzPatrick nuclear generating station
GinnaR. E. Ginna nuclear generating station
NERNewEnergy Receivables LLC
PCI  Potomac Capital Investment Corporation and its subsidiaries
PEC L.P.PECO Energy Capital, L.P.
PECO Trust IIIPECO Energy Capital Trust III
PECO Trust IVPECO Energy Capital Trust IV
Pepco Energy Services or PES  Pepco Energy Services, Inc. and its subsidiaries
PHI CorporatePHI in its corporate capacity as a holding company
PHISCOPHI Service Company
RPGRenewable Power Generation
SolGenSolGen, LLC
TMIThree Mile Island nuclear facility
UIIUnicom Investments, Inc.
1

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
ABOAccumulated Benefit Obligation
AECAlternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AESOAlberta Electric Systems Operator
AFUDCAllowance for Funds Used During Construction
AMIAdvanced Metering Infrastructure
AOCIAccumulated Other Comprehensive Income (Loss)
ARCAsset Retirement Cost
AROAsset Retirement Obligation
ARPAlternative Revenue Program
ASAAsset Sale Agreement
BGS  Basic Generation Service
Brookfield RenewableBrookfield Renewable Partners, L.P.
CAISOCalifornia ISO
CBAsCollective Bargaining Agreements
CERCLAComprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CESClean Energy Standard
Clean Air ActClean Air Act of 1963, as amended
Clean Water ActFederal Water Pollution Control Amendments of 1972, as amended
CODMChief Operating Decision Maker
Conectiv  Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods
DC PLUGDistrict of Columbia Power Line Undergrounding Initiative
DCPSC  District of Columbia Public Service Commission
DOEUnited States Department of Energy
DOEEDepartment of Energy & Environment
DOJUnited States Department of Justice
DPPDeferred Purchase Price
DPSC  Delaware Public Service Commission
DSPDefault Service Provider
EDFElectricite de France SA and its subsidiaries
EIMAEnergy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPAUnited States Environmental Protection Agency
ERCOTElectric Reliability Council of Texas
ERISAEmployee Retirement Income Security Act of 1974, as amended
EROAExpected Rate of Return on Assets
ERPEnterprise Resource Program
FASBFinancial Accounting Standards Board
FEJAIllinois Public Act 99-0906 or Future Energy Jobs Act
FERCFederal Energy Regulatory Commission
FRCCFlorida Reliability Coordinating Council
FRRFixed Resource Requirement
GAAPGenerally Accepted Accounting Principles in the United States
GCR  Gas Cost Rate
GHGGreenhouse Gas
GSAGeneration Supply Adjustment
2

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
GWhGigawatt hour
ICCIllinois Commerce Commission
ICEIntercontinental Exchange
IIPInfrastructure Investment Program
Illinois Settlement LegislationLegislation enacted in 2007 affecting electric utilities in Illinois
IPAIllinois Power Agency
IRCInternal Revenue Code
IRSInternal Revenue Service
ISOIndependent System Operator
ISO-NEISO New England Inc.
NYISONew York ISO
kVKilovolt
kWhKilowatt-hour
LIBORLondon Interbank Offered Rate
LLRWLow-Level Radioactive Waste
LNGLiquefied Natural Gas
LTIPLong-Term Incentive Plan
MATSU.S. EPA Mercury and Air Toxics Standards
MDEMaryland Department of the Environment
MDPSCMaryland Public Service Commission
MGPManufactured Gas Plant
MISOMidcontinent Independent System Operator, Inc.
mmcfMillion Cubic Feet
MOPRMinimum Offer Price Rule
MRVMarket-Related Value
MWMegawatt
MWhMegawatt hour
N/ANot applicable
NAVNet Asset Value
NDTNuclear Decommissioning Trust
NEILNuclear Electric Insurance Limited
NERCNorth American Electric Reliability Corporation
NJBPU  New Jersey Board of Public Utilities
NJDEPNew Jersey Department of Environmental Protection
Non-Regulatory Agreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSANuclear Operating Services Agreement
NPDESNational Pollutant Discharge Elimination System
NPNSNormal Purchase Normal Sale scope exception
NRCNuclear Regulatory Commission
NWPANuclear Waste Policy Act of 1982
NYMEXNew York Mercantile Exchange
NYPSCNew York Public Service Commission
OCIOther Comprehensive Income
OIESOOntario Independent Electricity System Operator
OPEBOther Postretirement Employee Benefits
3

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
PA DEPPennsylvania Department of Environmental Protection
PAPUCPennsylvania Public Utility Commission
PCBPolychlorinated Biphenyl
PGCPurchased Gas Cost Clause
PG&EPacific Gas and Electric Company
PJMPJM Interconnection, LLC
POLRProvider of Last Resort
PPAPower Purchase Agreement
PP&EProperty, Plant, and Equipment
Price-Anderson ActPrice-Anderson Nuclear Industries Indemnity Act of 1957
PRPPotentially Responsible Parties
PSEGPublic Service Enterprise Group Incorporated
PVPhotovoltaic
RCRAResource Conservation and Recovery Act of 1976, as amended
RECRenewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RESRetail Electric Suppliers
RFPRequest for Proposal
RiderReconcilable Surcharge Recovery Mechanism
RGGIRegional Greenhouse Gas Initiative
RMCRisk Management Committee
RNFRevenue Net of Purchased Power and Fuel Expense
ROE  Return on equity
ROURight-of-use
RPSRenewable Energy Portfolio Standards
RTEPRegional Transmission Expansion Plan
RTORegional Transmission Organization
S&PStandard & Poor’s Ratings Services
SECUnited States Securities and Exchange Commission
SERCSERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SGIGSmart Grid Investment Grant from DOE
SNFSpent Nuclear Fuel
SOASociety of Actuaries
SOSStandard Offer Service
SPPSouthwest Power Pool
SSASocial Security Administration
TCJATax Cuts and Jobs Act
Transition Bond Charge  Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses, and fees
Transition Bonds  Transition Bonds issued by ACE Funding
U.S. Court of Appeals for the D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
VIEVariable Interest Entity
WECCWestern Electric Coordinating Council
4

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
ZECZero Emission Credit
ZESZero Emission Standard
5

FILING FORMAT
This combined Annual Report on Form 10-K is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, including those factors discussed with respect to the Registrants discussed in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies, and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants’ website at www.exeloncorp.com. Information contained on the Registrants’ website shall not be deemed incorporated into, or to be a part of, this Report.

6

PART I
ITEM 1. 
General
Corporate Structure and Business and Other Information
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Name of Registrant  Business  Service
Territories
Exelon Generation
Company, LLC
Generation, physical delivery, and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy, and other energy-related products and services.Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions
Commonwealth Edison CompanyPurchase and regulated retail sale of electricityNorthern Illinois, including the City of Chicago
Transmission and distribution of electricity to retail customers
PECO Energy CompanyPurchase and regulated retail sale of electricity and natural gasSoutheastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric CompanyPurchase and regulated retail sale of electricity and natural gasCentral Maryland, including the City of Baltimore (electricity and natural gas)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLCUtility services holding company engaged, through its reportable segments Pepco, DPL, and ACEService Territories of Pepco, DPL, and ACE
Potomac Electric 
Power Company
  Purchase and regulated retail sale of electricity  District of Columbia and Major portions of Montgomery and Prince George’s Counties, Maryland
Transmission and distribution of electricity to retail customers
Delmarva Power & Light CompanyPurchase and regulated retail sale of electricity and natural gasPortions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPortions of New Castle County, Delaware (natural gas)
Atlantic City Electric CompanyPurchase and regulated retail sale of electricityPortions of Southern New Jersey
Transmission and distribution of electricity to retail customers
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Business Services
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. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
7

Generation
Generation, one of the largest competitive electric generation companies in the United States as measured by owned and contracted MW, physically delivers and markets power across multiple geographic regions through its customer-facing business, Constellation. Constellation sells electricity and natural gas, including renewable energy, in competitive energy markets to both wholesale and retail customers. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation's fleet also provides geographic and supply source diversity. Generation’s customers include distribution utilities, municipalities, cooperatives, financial institutions, and commercial, industrial, governmental, and residential customers in competitive markets. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers.
Generation is a public utility under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity, and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction over ratemaking includes the authority to suspend the market-based rates of utilities and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities.
RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE, and SPP as RTOs and CAISO and NYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and NYMEX, and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC.
Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional, and local agencies, including the NRC, and Federal and state environmental protection agencies. Additionally, Generation is subject to NERC mandatory reliability standards, which protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.
8

Generating Resources
At December 31, 2020, the generating resources of Generation consisted of the following:
Type of CapacityMW
Owned generation assets(a)(b)
Nuclear18,880 
Fossil (primarily natural gas and oil)9,340 
       Renewable(c)
3,051 
Owned generation assets31,271 
Contracted generation(d)
3,966 
Total generating resources35,237 
__________
(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 wind, hydroelectric, solar, and biomass generation.
(d)Electric supply procured under site specific agreements.
Generation has five reportable segments, as described in the table below, representing the different geographical areas in which Generation’s owned generating resources are located and Generation's customer-facing activities are conducted.
Segment
Net Generation Capacity (MW)(a)
% of Net Generation CapacityGeographical Area
Mid-Atlantic9,729 31 %Eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina
Midwest11,911 38 %Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region
New York1,971 %NYISO
ERCOT3,623 12 %Electric Reliability Council of Texas
Other Power Regions4,037 13 %New England, South, West, and Canada
Total31,271 100 %
__________
(a)Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.
Nuclear Facilities
Generation has ownership interests in thirteen nuclear generating stations currently in service, consisting of 23 units with an aggregate of 18,880 MW of capacity. These stations include FitzPatrick located in Scriba, New York, which was acquired on March 31, 2017 and exclude TMI located in Middletown, Pennsylvania, which permanently ceased generation operations on September 20, 2019 and Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018 and was subsequently sold to Holtec International (Holtec) on July 1, 2019. Generation wholly owns all of its nuclear generating stations, except for undivided ownership interests in three jointly-owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), and Salem (42.59% ownership), which are consolidated in Exelon’s and Generation's financial statements relative to its proportionate ownership interest in each unit, and a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements.
9

Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has an option to sell its 49.99% equity interest in CENG to Generation. The put option became exercisable on January 1, 2016 and may be exercised any time until June 30, 2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option and sell its ownership share in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC and the FERC. The FERC approval was obtained on July 30, 2020. From the date the put was exercised, the process and regulatory approvals could take one to two years to complete.
See ITEM 2. PROPERTIES for additional information on Generation's nuclear facilities, Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the disposition of Oyster Creek, and Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the CENG consolidation.
Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2020, 2019, and 2018 electric supply (in GWh) generated from the nuclear generating facilities was 62%, 64%, and 68%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric, and renewable generation and electric supply purchased for resale. Generation’s wholesale and retail power marketing activities are, in part, supplied by the output from the nuclear generating stations. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information 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. Generation’s operations from its nuclear plants have historically had minimal environmental impact and the plants have a safe operating history.
Generation manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s wholesale and retail power marketing activities. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. During 2020, 2019, and 2018, the nuclear generating facilities operated by Generation, achieved capacity factors of 95.4%, 95.7%, and 94.6%, respectively, at ownership percentage.
In addition to the maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation also has extensive safety systems in place 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 nuclear generating stations, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, and environmental and radiological aspects of those stations. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results and communicates its assessment on a semi-annual basis. All nuclear generating stations operated by Generation are categorized by the NRC in the Licensee Response Column, which is the highest of five performance bands. The NRC may modify, suspend, or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act or the terms of the operating licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures and/or operating costs for nuclear generating facilities.
Licenses
Generation has original 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals from the NRC for all its nuclear units except Clinton. PSEG has received 20-year operating license renewals for Salem Units 1 and 2. Peach Bottom has received a second 20-year license
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renewal from the NRC for Units 2 and 3. On August 27, 2020, Generation announced that it intends to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
The following table summarizes the current license expiration dates for Generation’s operating nuclear facilities in service:
StationUnit
In-Service
Date(a)
Current License
Expiration
Braidwood19882046
19882047
Byron19852044
19872046
Calvert Cliffs19752034
19772036
Clinton(b)
19872027
Dresden19702029
19712031
FitzPatrick19742034
LaSalle19842042
19842043
Limerick19862044
19902049
Nine Mile Point19692029
19882046
Peach Bottom19742053
19742054
Quad Cities19732032
19732032
Ginna19702029
Salem19772036
19812040
__________
(a)Denotes year in which nuclear unit began commercial operations.
(b)Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has notified the NRC that any license renewal application would not be filed until the first quarter of 2024. In 2019, the NRC approved a change of the operating license expiration for Clinton from 2026 to 2027.
The operating license renewal process takes approximately four to five years from the commencement of the renewal process, which includes approximately two years for Generation to develop the application and approximately two years for the NRC to review the application. Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation’s operating nuclear generating stations except for Clinton, Peach Bottom, Byron, and Dresden. Clinton depreciation provisions are based on an estimated useful life of 2027 which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the second renewal of its operating licenses. Byron and Dresden depreciation provisions are based on the announced shutdown dates of September 2021 and November 2021, respectively. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois ZES and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on early retirements.
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Nuclear Waste Storage and Disposal
There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities on-site in storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask storage facilities to support operations.
As of December 31, 2020, Generation had approximately 87,100 SNF assemblies (21,600 tons) stored on site in SNF pools or dry cask storage which includes SNF assemblies at Zion Station, for which Generation retains ownership even though the responsibility for decommissioning Zion Station has been assumed by another party, and TMI, which is no longer operational. See the Decommissioning section below for additional information regarding Zion Station. All currently operating Generation-owned nuclear sites have on-site dry cask storage. TMI's on-site dry cask storage is projected to be in operation in 2021. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites through the end of the license renewal periods and through decommissioning.
For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into such an agreement, although neither state currently has an operational site and none is anticipated to be operational for the next ten years.
Generation ships its Class A LLRW, which represents 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina, which have enough storage capacity to store all Class A LLRW for the life of all stations in Generation's nuclear fleet. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Salem), and Connecticut.
Generation utilizes on-site storage capacity at all its stations to store and stage for shipping Class B and Class C LLRW. Generation has a contract through 2032 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently stored at each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW from Generation’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still be required to utilize on-site storage at its stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store all Class B and Class C LLRW for the life of all stations in Generation’s nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize on-site storage and cost impacts.
Nuclear Insurance
Generation is subject to liability, property damage, and other risks associated with major incidents at all of its nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
For information regarding property insurance, see ITEM 2. PROPERTIES — Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial statements.
Decommissioning
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. The ultimate decommissioning obligation will be funded by the NDT funds. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
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OPERATIONS — Exelon Corporation, Liquidity and Capital Resources; ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates, Nuclear Decommissioning, Asset Retirement Obligations, and Nuclear Decommissioning Trust Fund Investments; and Note 3 — Regulatory Matters, Note 2Mergers, Acquisitions, and Dispositions, Note 18 — Fair Value of Financial Assets and Liabilities, and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.
Oyster Creek Decommissioning. On July 1, 2019, Generation completed the sale with Holtec and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), of Oyster Creek under which Holtec has assumed the responsibility for decommissioning. See Note 2Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Zion Station Decommissioning. On September 1, 2010, Generation completed an ASA with EnergySolutions, Inc. and its wholly owned subsidiaries, EnergySolutions, LLC and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Fossil and Renewable Facilities (including Hydroelectric)
Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) Wyman; (2) certain wind project entities and a biomass project entity with minority interest owners; and (3) EGRP which is owned 49% by another owner. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding EGRP which is a VIE. Generation’s fossil and renewable generating stations are all operated by Generation, with the exception of Wyman, which is operated by a third party. In 2020, 2019, and 2018, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 9%, 11%, and 11%, respectively, of Generation’s total electric supply. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. On December 8, 2020, Generation entered into an agreement to sell a significant portion of Generation's solar business. See ITEM 2. PROPERTIES for additional information regarding Generation's electric generating facilities and Note 2 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the sale of Generation's solar business.
Licenses
Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid, which include Generation's Conowingo Hydroelectric Project (Conowingo) and Muddy Run Pumped Storage Facility Project (Muddy Run). Muddy Run's license expires on December 1, 2055. On August 29, 2012, Generation submitted a hydroelectric license application to the FERC for a new license for Conowingo. Based on the FERC procedural schedule, the FERC licensing process for Conowingo was not completed prior to the expiration of the plant’s license on September 1, 2014. As a result, on September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. The annual license renews automatically absent any further FERC action. The stations are currently being depreciated over their estimated useful lives, which include actual and anticipated license renewal periods. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on Conowingo.
Insurance
Generation maintains business interruption insurance for its renewable projects, but not for its fossil and hydroelectric operations unless required by contract or financing agreements. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on financing agreements. Generation maintains both property damage and liability insurance. For property damage and liability claims for these operations, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial conditions and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES — Generation.
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Contracted Generation
In addition to energy produced by owned generation assets, Generation sources electricity from plants it does not own under long-term contracts. The following tables summarize Generation’s long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by region, in effect as of December 31, 2020:
RegionNumber of
Agreements
Expiration 
Dates
Capacity (MW)
Mid-Atlantic
2021 - 2032183 
Midwest2021 - 2032351 
ERCOT2021 - 2035864 
Other Power Regions17 2021 - 20322,568 
Total33 3,966 
20212022202320242025ThereafterTotal
Capacity Expiring (MW)884 304 103 101 461 2,113 3,966 
Fuel
The following table shows sources of electric supply in GWh for 2020 and 2019: 
Source of Electric Supply
20202019
Nuclear(a)
175,085 181,326 
Purchases — non-trading portfolio79,972 70,939 
Fossil (primarily natural gas and oil)19,501 21,554 
Renewable(b)
7,052 7,777 
Total supply281,610 281,596 
 
__________
(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g., CENG).  Nuclear generation for 2020 and 2019 includes physical volumes of 35,052 GWh and 35,745 GWh, respectively, for CENG.
(b)Includes wind, hydroelectric, solar, and biomass generating assets.
The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride, and the fabrication of fuel assemblies. Generation has inventory in various forms and does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet the nuclear fuel requirements of its nuclear units.
Natural gas is procured through long-term and short-term contracts, as well as spot-market purchases. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.
Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures, using both over-the-counter and exchange-traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.
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Power Marketing
Generation’s integrated business operations include physical delivery and marketing of power. Generation largely obtains physical power supply from its owned and contracted generation in multiple geographic regions. The commodity risks associated with the output from owned and contracted generation is managed using various commodity transactions including sales to customers. The main objective is to obtain low-cost energy supply to meet physical delivery obligations to both wholesale and retail customers. Generation sells electricity, natural gas, and other energy related products and solutions to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets. Where necessary, Generation may also purchase transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs.
Price and Supply Risk Management
Generation also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation may also enter into transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 2021 and beyond for portions of its electricity portfolio that are unhedged. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 2021. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including sales to the Utility Registrants to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices. The risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retail power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
Capital Expenditures
Generation’s business is capital intensive and requires significant investments primarily in nuclear fuel and energy generation assets. Generation’s estimated capital expenditures for 2021 include Generation's share of the investment in the co-owned Salem plant and the total capital expenditures for CENG. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2021 capital expenditures.

Utility Registrants
Merger with Pepco Holdings, Inc.
On March 23, 2016, Exelon completed the merger among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub), and PHI. As a result of that merger, Merger Sub was merged into PHI (the PHI merger) with PHI surviving as a wholly owned subsidiary of Exelon and EEDC, a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO, and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI merger, Exelon, and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL, and ACE to a special purpose subsidiary of EEDC.
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Utility Operations
Service Territories and Franchise Agreements
The following table presents the size of service territories, populations of each service territory and the number of customers within each service territory for the Utility Registrants as of December 31, 2020:
ComEdPECOBGEPepcoDPLACE
Service Territories (in square miles)
Electric11,400 2,100 2,300 640 5,400 2,800 
Natural GasN/A1,960 3,050 N/A270 N/A
Total11,400 2,100 3,250 640 5,400 2,800 
Service Territory Population (in millions)
Electric9.6 4.0 3.0 2.4 1.5 1.1 
Natural GasN/A2.5 2.9 N/A0.6 N/A
Total9.6 4.0 3.1 2.4 1.5 1.1 
Main CityChicagoPhiladelphiaBaltimoreDistrict of ColumbiaWilmingtonAtlantic City
Main City Population2.7 1.6 0.6 0.7 0.1 0.1 
Number of Customers (in millions)
Electric4.1 1.7 1.3 0.9 0.5 0.6 
Natural GasN/A0.5 0.7 N/A0.1 N/A
Total4.1 1.7 1.3 0.9 0.5 0.6 
The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations.
Utility Regulations
State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight.
RegistrantCommission
ComEdICC
PECOPAPUC
BGEMDPSC
PepcoDCPSC/MDPSC
DPLDPSC/MDPSC
ACENJBPU
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.
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Seasonality Impacts on Delivery Volumes
The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for either summer cooling or winter heating. For PECO, BGE, and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating.
ComEd, BGE, Pepco, and DPL Maryland have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd's, BGE's, Pepco's, and DPL's Maryland electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by delivery volumes. PECO's and DPL's Delaware electric distribution revenues and natural gas distribution revenues and ACE's electric distribution revenues are impacted by delivery volumes.
Electric and Natural Gas Distribution Services
The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. PECO's, BGE's, and DPL's electric and gas distribution costs and Pepco's and ACE's electric distribution costs have generally been recovered through traditional rate case proceedings. However, the MDPSC and the DCPSC allow utilities to file multi-year rate plans. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies.
ComEd, Pepco, and ACE customers have the choice to purchase electricity, and PECO, BGE, and DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. The Utility Registrants remain the distribution service providers for all customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO and BGE also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For natural gas, DPL does not retain default service obligations for its residential customers.
For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and therefore do not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas procurement costs without mark-up and therefore record equal and offsetting amounts of Operating revenues and Purchased power and fuel expense related to the electricity and/or natural gas. As a result, fluctuations in electricity or natural gas sales and procurement costs have no impact on the Utility Registrants’ Net Income.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas distribution services.
Procurement of Electricity and Natural Gas
The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by their respective state commissions. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the utility electric load and supply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income.
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PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE, and DPL have annual firm supply and transportation contracts of 132,000 mmcf, 264,000 mmcf and 61,000 mmcf, respectively. In addition, to supplement gas supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the following sources:
Peak Natural Gas Sources (in mmcf)
LNG FacilityPropane-Air Plant
Underground Storage Service Agreements (a)
PECO1,200 150 19,400 
BGE1,056 550 22,000 
DPL250 N/A3,900 
___________
(a)Natural gas from underground storage represents approximately 28%, 20%, and 33% of PECO's, BGE’s, and DPL's 2020-2021 heating season planned supplies, respectively.
PECO, BGE, and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE, and DPL make these sales as part of a program to balance its supply and cost of natural gas. The off-system gas sales are not material to PECO, BGE, and DPL.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price Risk (All Registrants), for additional information regarding Utility Registrants' contracts to procure electric supply and natural gas.
Energy Efficiency Programs
The Utility Registrants are generally allowed to recover costs associated with the energy efficiency and demand response programs they offer. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency.
ComEd is allowed to earn a return on its energy efficiency costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Capital Investment
The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of their systems. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2021 capital expenditures.
Transmission Services
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees.
PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity, and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of certain of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-
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access basis using the transmission facilities of the PJM transmission owners at rates based on the costs of transmission service.
The Utility Registrants' transmission rates are established based on a formula that was initially approved by FERC as shown below:
Approval Date
ComEdJanuary 2008
PECODecember 2019
BGEApril 2006
PepcoApril 2006
DPLApril 2006
ACEApril 2006
Employees
The Registrants strive to create a workplace that is diverse, innovative, and safe for their employees. In order to provide the services and products that their customers expect, the Registrants must create the best teams. These teams must reflect the diversity of the communities that the Registrants serve. Therefore, the Registrants strive to attract highly qualified and diverse talent and routinely review their hiring and promotion practices to ensure they maintain equitable and bias free processes to neutralize any unconscious bias. The Registrants provide growth opportunities, competitive compensation and benefits, and a variety of training and development programs. The Registrants are committed to helping employees grow their skills and careers largely through numerous training opportunities in technical, safety and business acumen areas, mentorship programs, and continuous feedback and development discussions and evaluations. Employees are encouraged to thrive outside the workplace as well. The Registrants provide a full suite of wellness benefits targeted at supporting work-life balance, physical, mental and financial health, and industry-leading paid leave policies.
The Registrants conduct an employee engagement survey every other year to help identify their successes and areas where they can grow. The survey results are reviewed with senior management and the Exelon Board of Directors.
Diversity Metrics
The following tables show diversity metrics for all employees and management as of December 31, 2020:
EmployeesExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Female(a) (b)
7,993 2,492 1,517 727 765 1,281 366 154 121 
People of Color(b)
9,298 2,083 2,432 890 1,067 1,748 898 194 139 
Aged <303,268 1,363 625 279 273 425 183 85 62 
Aged 30-5017,119 6,712 3,491 1,292 1,694 2,207 756 466 369 
Aged >5011,953 4,407 2,138 1,227 1,172 1,594 517 385 219 
Total Employees(c)
32,340 12,482 6,254 2,798 3,139 4,226 1,456 936 650 

Management(d)
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Female(a) (b)
1,175 299 209 112 112 177 46 14 19 
People of Color(b)
1,132 220 276 104 132 232 112 27 14 
Aged <3078 51 11 — 
Aged 30-502,790 1,220 441 137 238 341 102 59 47 
Aged >502,219 841 369 213 170 277 73 63 34 
Within 10 years of retirement eligibility2,936 1,113 487 250 235 370 95 82 46 
Total Employees in Management(c)
5,087 2,112 814 355 411 629 178 126 81 
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 __________
(a)The Registrants are devoted to creating an environment that allows women to stay in the workforce, grow with the company, and move up the ranks, all with parity of pay. Exelon employs an independent third-party vendor to run regression analysis on all management positions each year. The analysis consistently shows that the Registrants have no systemic pay equity issues.
(b)This is based on self-disclosed information.
(c)Total employees represents the sum of the aged categories.
(d)Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and supervisory responsibilities.
Turnover Rates
As turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management frequently reviews succession planning to ensure the Registrants are prepared when positions become available.
The table below shows the average turnover rate for all employees for the last three years of 2018 to 2020:
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Retirement Age4.13 %4.80 %3.69 %2.64 %3.64 %4.31 %4.90 %3.70 %3.37 %
Voluntary2.87 %3.88 %1.37 %1.55 %1.37 %2.18 %2.51 %1.10 %1.21 %
Non-Voluntary0.97 %0.86 %0.61 %1.15 %0.97 %0.94 %1.78 %0.25 %0.63 %
Collective Bargaining Agreements
Approximately 37% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of December 31, 2020:
Total Employees Covered by CBAsNumber of CBAs
CBAs New and Renewed in 2020(a)
Total Employees Under CBAs
New and Renewed
in 2020
Exelon11,964 32 11 1,715 
Generation3,418 22 1,001 
ComEd3,476 71 
PECO1,350 — — 
BGE1,423 — — 
PHI2,203 626 
Pepco954 — — 
DPL626 626 
ACE390 — — 
 __________
(a)Does not include CBAs that were extended in 2020 while negotiations are ongoing for renewal.
Environmental Regulation
General
The Registrants are subject to comprehensive and complex environmental legislation and regulation at the federal, state, and local levels, including requirements relating to climate change, air and water quality, solid and hazardous waste, and impacts on species and habitats.
The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice President, Corporate Strategy & Chief Innovation and Sustainability Officer; the Senior Vice President, Competitive Market Policy; and the Vice President, Corporate Environmental Strategy, as well as senior management of the Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Exelon Board of Directors has delegated to its Generation Oversight Committee and the Corporate
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Governance Committee the authority to oversee Exelon’s compliance with health, environmental, and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental, health, and safety issues related to these companies.
Climate Change Mitigation
Exelon supports comprehensive federal climate legislation, including a cap-and-trade program for GHG emissions that addresses the urgent need to substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the economy. In the absence of comprehensive federal legislation, Exelon supports EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act.
The Registrants currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations addressing GHG emissions. Generation produces electricity predominantly from low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar PV) and neither owns nor operates any coal-fueled generating assets. Generation’s natural gas and biomass fired generating plants produce GHG emissions, most notably CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry.
Other GHG emission sources associated with the Utility Registrants include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. In addition, PECO, BGE, and DPL distribute natural gas and Generation sells natural gas at retail; and consumers’ use of such natural gas produces GHG emissions.
International Climate Change Agreements. At the international level, the United States is a party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average temperature increase and to develop national GHG reduction commitments. On November 4, 2020, the United States formally withdrew from the Paris Agreement, retracting its commitment to reduce domestic GHG emissions by 26%-28% by 2025 compared with 2005 levels. However, on January 20, 2021, President Biden accepted the Paris Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The Biden administration has announced its intent to pursue ambitious GHG reductions in the United States and internationally.
Federal Climate Change Legislation and Regulation. It is highly uncertain whether federal legislation to significantly reduce GHG emissions will be enacted in the near-term. If such legislation were adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively impact the value of Exelon’s low-carbon fleet.
The Clean Power Plan and Affordable Clean Energy Rule. The EPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or expanded zero-emissions generation. In July 2019, the EPA published its final Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit was consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit held the Affordable Clean Energy Rule to be unlawful, vacated the rule, and remanded it to the EPA. The EPA has indicated it will promulgate new GHG limits for existing power plants in accordance with the U.S. Court of Appeals for the D.C. Circuit's order.
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State Climate Change Legislation and Regulation. A number of states in which the Registrants operate have state and regional programs to reduce GHG emissions and renewable and other portfolio standards, which impact the power sector. See discussion below for additional information on renewable and other portfolio standards. As the nation’s largest generator of carbon-free electricity, Generation’s fleet supports these efforts to produce safe, reliable electricity with minimal GHGs.
Eleven northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia) currently participate in the RGGI, which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances. In October 2019, the Governor of Pennsylvania issued an Executive Order directing the PA DEP to begin a rulemaking process to allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector. On November 7, 2020, the PA DEP proposed its rule.
Broader state programs impact other sectors as well, such as New York’s Climate Leadership and Community Protection Act, which establishes statewide emission limits; and Massachusetts’ Clean Energy and Climate Plan, which aims to reduce GHG emissions across all sectors through increased efficiency in buildings and vehicles, the electrification of vehicles and thermal conditioning in buildings, and the replacement of carbon intensive fuels with renewable energy sources.
While the Registrants cannot predict the nature of future regulations or how such regulations might impact future financial statements, Generation has a low emission portfolio, and GHG restrictions would likely benefit zero- and low-emission generating units relative to higher-emission fossil fuel-fired generating units.
In addition, Exelon facilities and operations are subject to the global impacts of climate change. Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for additional information.
Renewable and Clean Energy Standards
Thirty states and the District of Columbia, incorporating the vast majority of states where Exelon operates, have adopted some form of renewable or clean energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility Registrants comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. Illinois, New York, and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Exelon operates are considering similar programs.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Air Quality
Mercury and Air Toxics Standards (MATS). In 2011, the EPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from power plants. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases, and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. In 2016, in response to a Supreme Court decision requiring the EPA to consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a supplemental finding that, after considering costs, it remained appropriate and necessary. On May 22, 2020, the EPA reversed course, publishing a final rule revoking the "appropriate and necessary" finding underpinning MATS. A coal mining company filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit seeking vacatur of MATS based on the EPA’s May 22, 2020 finding; on September 11, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a motion by Exelon and two other
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entities to intervene in that lawsuit to defend MATS, and on September 28, 2020, the U.S. Court of Appeals for the D.C. Circuit issued an Executive Order holding this portion of the MATS litigation in abeyance. On July 21, 2020, Exelon and two other entities filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS. This portion of the case is also being held in abeyance in response to the DOJ’s motion filed February 12, 2021. On January 20, 2021, President Biden issued an Executive Order directing the EPA to reconsider its May 22, 2020 recission by August 2021; the EPA will likely re-affirm the finding that it is appropriate and necessary to regulate power plant emissions of hazardous air pollutants. As a result, this litigation is likely to be rendered moot, and MATS will likely remain in place in the interim.
Water Quality
Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of Exelon's facilities discharge stormwater, industrial wastewater, and/or cooling water into waterways and are therefore subject to these regulations and operate under NPDES permits.
Clean Water Act Section 316(b) is implemented through the NDPES program and requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. Generation’s power generation facilities with cooling water intake systems are subject to the EPA’s Section 316(b) regulations finalized in 2014; the regulation’s requirements have been or will be addressed through renewal of these facilities’ NPDES permits. 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 EPA’s 2014 rule will have on the operation of its generating facilities and its financial statements. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the final rule does not mandate cooling towers and allows state permitting directors to require alternative, less costly technologies and/or operational measures, based on a site-specific assessment of the feasibility, costs, and benefits of available options.
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
Under Clean Water Act Section 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill activities in Waters of the United States.
Where Registrants’ facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be required to obtain a state water quality certification under Clean Water Act section 401.
Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.
Solid and Hazardous Waste and Environmental Remediation
CERCLA provides for response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, many of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. Such statutes apply in many states where the Registrants currently own or
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operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these Federal and state environmental laws. Under these laws, the Registrants may be liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. The Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of sites or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco, and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2021 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is estimated to be approximately $35 million which consists primarily of $30 million at ComEd.
As of December 31, 2020, the Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial Statements.
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Information about our Executive Officers as of February 24, 2021
Exelon
NameAgePositionPeriod
Crane, Christopher M.62 Chief Executive Officer, Exelon;2012 - Present
President, Exelon2008 - Present
Cornew, Kenneth W.55 Senior Executive Vice President and Chief Commercial Officer, Exelon;2013 - Present
President and CEO, Generation2013 - Present
Butler, Calvin G.51 Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities2019 - Present
Chief Executive Officer, BGE2014 - 2019
Dominguez, Joseph58 Chief Executive Officer, ComEd2018 - Present
Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon2015 - 2018
Glockner, David60 Executive Vice President, Compliance and Audit, Exelon2020 - Present
Chief Compliance Officer, Citadel LLC2017 - 2020
Regional Director, U.S. Securities and Exchange Commission2013 - 2017
Hanson, Bryan C.55 Executive Vice President and Chief Generation Officer, Generation2020 - Present
President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Generation2015 - 2020
Innocenzo, Michael A.55 President and Chief Executive Officer, PECO2018 - Present
Senior Vice President and Chief Operations Officer, PECO2012 - 2018
Khouzami, Carim V.45 Chief Executive Officer, BGE2019 - Present
Senior Vice President, Chief Operating Officer, Exelon Utilities2018 - 2019
Senior Vice President, Chief Financial Officer, Exelon Utilities2016 - 2018
Senior Vice President, Chief Integration Officer, Exelon2014 - 2016
Velazquez, David M.61 President and Chief Executive Officer, PHI2016 - Present
President and Chief Executive Officer, Pepco, DPL, and ACE2009 - Present
Executive Vice President, Pepco Holdings, Inc.2009 - 2016
Von Hoene Jr., William A.67 Senior Executive Vice President and Chief Strategy Officer, Exelon2012 - Present
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NameAgePositionPeriod
Nigro, Joseph56 Senior Executive Vice President and Chief Financial Officer, Exelon2018 - Present
Executive Vice President, Exelon; Chief Executive Officer, Constellation2013 - 2018
Souza, Fabian E.50 Senior Vice President and Corporate Controller, Exelon2018 - Present
Senior Vice President and Deputy Controller, Exelon2017 - 2018
Vice President, Controller and Chief Accounting Officer, The AES Corporation2015 - 2017
Generation
NameAgePositionPeriod
Crane, Christopher M.62 Principle Executive Officer, Generation2020 - Present
Chief Executive Officer, Exelon;2012 - Present
President, Exelon2008 - Present
Cornew, Kenneth W.55 Senior Executive Vice President and Chief Commercial Officer, Exelon;2013 - Present
President and Chief Executive Officer, Generation2013 - Present
Swahl, William51 Senior Vice President, Generation; Chief Operating Officer, Exelon Power2021 - Present
Vice President, Generation; Vice President, Mid-Atlantic Operations, Exelon Power2014 - 2020
Hanson, Bryan C.55 Executive Vice President and Chief Generation Officer, Generation2020 - Present
President and Chief Nuclear Officer, Exelon Nuclear, Senior Vice President, Generation2015 - 2020
McHugh, James49 Executive Vice President, Exelon; Chief Executive Officer, Constellation2018 - Present
Senior Vice President, Portfolio Management & Strategy, Constellation2016 - 2018
Vice President, Portfolio Management, Constellation2012 - 2016
Rhoades, David54 Senior Vice President, Generation; President and Chief Nuclear Officer, Exelon Nuclear2020 - Present
Chief Operating Officer, Fleet Operations, Exelon Nuclear2015 - 2020
Wright, Bryan P.54 Senior Vice President and Chief Financial Officer, Generation2013 - Present
Bauer, Matthew N.44 Vice President and Controller, Generation2016 - Present
Vice President and Controller, BGE2014 - 2016
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ComEd
NameAgePositionPeriod
Dominguez, Joseph58 Chief Executive Officer, ComEd2018 - Present
Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon2015 - 2018
Donnelly, Terence R.60 President and Chief Operating Officer, ComEd2018 - Present
Executive Vice President and Chief Operating Officer, ComEd2012 - 2018
Jones, Jeanne M.41 Senior Vice President, Chief Financial Officer and Treasurer, ComEd2018 - Present
Vice President, Finance, Exelon Nuclear2014 - 2018
Park, Jane48 Senior Vice President, Customer Operations, ComEd2018 - Present
Vice President, Regulatory Policy & Strategy, ComEd2016 - 2018
Director, Business Strategy & Technology, ComEd2014 - 2016
Gomez, Veronica51 Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd2017 - Present
Vice President and Deputy General Counsel, Litigation, Exelon2012 - 2017
Washington, Melissa51 Senior Vice President, Governmental and External Affairs, ComEd2019 - Present
Vice President, Governmental and External Affairs, ComEd2019 -2019
Vice President, External Affairs and Large Customer Services, ComEd2016 - 2019
Vice President, Corporate Affairs, Exelon Business Services Company2014 - 2016
Perez, David51 Senior Vice President, Distribution Operations, ComEd2019 - Present
Vice President, Transmission and Substation, ComEd2016 - 2019
Vice President, Regional Operations, ComEd2010 - 2016
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PECO
NameAgePositionPeriod
Innocenzo, Michael A.55 President and Chief Executive Officer, PECO2018 - Present
Senior Vice President and Chief Operations Officer, PECO2012 - 2018
McDonald, John63 Senior Vice President and Chief Operations Officer, PECO2018 - Present
Vice President, Integration, PHI2016 - 2018
Vice President, Technical Services2006 - 2016
Stefani, Robert J.47 Senior Vice President, Chief Financial Officer and Treasurer, PECO2018 - Present
Vice President, Corporate Development, Exelon2015 - 2018
Murphy, Elizabeth A.61 Senior Vice President, Governmental and External Affairs, PECO2016 - Present
Vice President, Governmental and External Affairs, PECO2012 - 2016
Webster Jr., Richard G.59 Vice President, Regulatory Policy and Strategy, PECO2012 - Present
Williamson, Olufunmilayo42 Senior Vice President, Customer Operations, PECO2020 - Present
Senior Vice President, Chief Commercial Risk Officer, Exelon2017 - 2020
Vice President, Commercial Risk Management, Exelon2015 - 2017
Gay, Anthony55 Vice President and General Counsel, PECO2019 - Present
Vice President, Governmental and External Affairs, PECO2016 - 2019
Associate General Counsel, Exelon2010 - 2016
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BGE
NameAgePositionPeriod
Khouzami, Carim V.45 Chief Executive Officer, BGE2019 - Present
Senior Vice President, Chief Operating Officer, Exelon Utilities2018 - 2019
Senior Vice President, Chief Financial Officer, Exelon Utilities2016 - 2018
Senior Vice President, Chief Integration Officer, Exelon2014 - 2016
Woerner, Stephen J.53 President, BGE2014 - Present
Chief Operating Officer, BGE2012 - Present
Vahos, David M.48 Senior Vice President, Chief Financial Officer and Treasurer, BGE2016 - Present
Vice President, Chief Financial Officer and Treasurer, BGE2014 - 2016
Núñez, Alexander G. 49 Senior Vice President, Regulatory Affairs and Strategy, BGE2020 - Present
Senior Vice President, Regulatory and External Affairs, BGE2016 - 2020
Vice President, Governmental and External Affairs, BGE2013 - 2016
Case, Mark D.59 Vice President, Strategy and Regulatory Affairs, BGE2012 - Present
Oddoye, Rodney44 Senior Vice President, Governmental and External Affairs, BGE2020 - Present
Vice President, Customer Operations, BGE2018 - 2020
Director, Northeast Regional Electric Operations, BGE2016 - 2018
Director, Financial Operations, BGE2015 - 2016
Olivier, Tamla48 Senior Vice President, Customer Operations, BGE2020 - Present
Senior Vice President, Constellation NewEnergy, Inc.2016 - 2020
VP, Human Resources, Exelon Business Services Company2012 - 2016
Corse, John60 Vice President and General Counsel, BGE2018 - Present
Associate General Counsel, Exelon2012 - 2018
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PHI, Pepco, DPL, and ACE
NameAgePositionPeriod
Velazquez, David M.61 President and Chief Executive Officer, PHI2016 - Present
Executive Vice President, Pepco Holdings, Inc.2009 - 2016
President and Chief Executive Officer, Pepco, DPL, and ACE2009 - Present
Anthony, J. Tyler56 Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and ACE2016 - Present
Senior Vice President, Distribution Operations, ComEd2010 - 2016
Barnett, Phillip S.57 Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL, and ACE2018 - Present
Senior Vice President and Chief Financial Officer, PECO2007 - 2018
Treasurer, PECO2012 - 2018
Lavinson, Melissa51 Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL, and ACE2018 - Present
Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation2015 - 2018
Stark, Wendy E.48 Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL, and ACE2019 - Present
Vice President and General Counsel, PHI, Pepco, DPL, and ACE2016 - 2018
Deputy General Counsel, Pepco Holdings, Inc.2012 - 2016
McGowan, Kevin M.59 Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL, and ACE2016 - Present
Vice President, Regulatory Affairs, Pepco Holdings, Inc.2012 - 2016
Dickens, Derrick56 Senior Vice President, Customer Operations, PHI2020 - Present
Vice President, Technical Services, BGE2016 - 2020
Director, Advanced Meter Infrastructure, PECO2012 - 2016
Humphrey, Marissa41Vice President, Regulatory Policy and Strategy, PHI, DPL, and ACE2021 - Present
Vice President Finance, Exelon Utilities2019 - 2020
Vice President, Finance, PHI2016 - 2019
ITEM 1A.RISK FACTORS
Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories below:
Market and Financial Factors primarily include:
the price of fuels, in particular the price of natural gas, which affects power prices,
the generation resources in the markets in which the Registrants operate,
the demand for electricity, reliability of service, and affordability in the markets where the Registrants conduct their business,
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the ability of the Registrants to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and the impacts on their results of operations due to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19),
the impacts of on-going competition, and
emerging technologies and business models, including those related to climate change mitigation and transition to a low carbon economy.
Regulatory, Legislative, and Legal Factors primarily include changes to, and compliance with, the laws and regulations that govern:
the design of power markets,
ZEC programs,
utility regulatory business models,
environmental and climate policy, and
tax policy.
Operational Factors primarily include:
changes in the global climate could produce extreme weather events, which could put the Registrant’s facilities at risk, and such changes could also affect the levels and patterns of demand for energy and related services,
the safe, secure, and effective operation of Generation’s nuclear facilities and the ability to effectively manage the associated decommissioning obligations,
the ability of the Registrants to maintain the reliability, resiliency, and safety of their energy delivery systems, which could affect the operating costs of the Registrants and the opinions of their customers and regulators, and
physical and cyber security risks for the Registrants as the owner-operators of generation, transmission, and distribution facilities and as participants in commodities trading.
Risks Related to the Planned Separation primarily include:
the timing and conditions associated with required regulatory approvals, which may affect the costs to achieve the separation and its timing,
challenges to achieving the benefits of separation, including maintaining investment grade credit ratings, and
the risk that the separation could be treated as a taxable transaction to both Exelon and its shareholders.
There may be further risks and uncertainties that are not presently known or that are not currently believed by the Registrants to be material that could negatively affect its consolidated financial statements in the future.
Market and Financial Factors
Generation is exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
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Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Generation's nuclear plants. Conversely, new demand sources such as electrification of transportation could increase demand and change demand patterns.
Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output.
The impact of sustained low market prices or depressed demand and over-supply could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation's financial statements primarily through accelerated depreciation and amortization expenses and one-time charges. See Note 7Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Cost of Fuel. Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. The supply markets for nuclear fuel, natural gas, and oil are subject to price fluctuations, availability restrictions, and counterparty default.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable energy technologies, energy efficiency, distributed generation, and energy storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations, and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could affect the Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to
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decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 10Asset Retirement Obligations and Note 15Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, Generation’s ability to hedge effectively its generation portfolio, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2020, approximately 23%, 19%, and 18% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. 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 specific project being required to repay the associated
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debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy could result in the impairment of certain project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement, and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its consolidated financial statements.
Financial performance and load requirements could be negatively affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
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The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants).
The impacts of significant economic downturns on the Utility Registrants' customers, such as less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms.
Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants’ credit risk.
The Registrants' results could be negatively affected by the impacts of COVID-19 (All Registrants).
COVID-19 is an evolving situation that could lead to extended disruption of economic activity in the Registrants’ respective markets. COVID-19 could negatively affect the Registrants’ ability to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and their results of operations. The Registrants cannot predict the extent of the impacts of COVID-19, which will depend on future developments and which are highly uncertain. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Executive Overview for additional information.
The Registrants could be negatively affected by the impacts of weather (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues at PECO, DPL Delaware, and ACE. Due to revenue decoupling, BGE, Pepco, and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period and are not affected by actual weather with the exception of major storms. ComEd’s customer rates are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the long-term in the areas where Registrants have generation, transmission, and distribution assets. The frequency in which weather conditions emerge outside the current expected climate norms could contribute to weather-related impacts discussed above.
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Long-lived assets, goodwill, and other assets could become impaired (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have material goodwill balances.
The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered.
ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s goodwill.
An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 8Property, Plant, and Equipment, Note 12Asset Impairments and Note 13Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.
The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance. Generation is exposed to other credit risks in the power markets that are beyond its control (All Registrants).
The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities.
The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and they could incur substantial costs to fulfill their obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these guarantees.
In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent amounts, if any, were already paid to the counterparties. In the spot markets, Generation is
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exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Regulatory, Legislative, and Legal Factors
Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets (Exelon and Generation).
Approximately 70% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations are impacted by (1) FERC’s and PJM's support for policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and for states' energy objectives and policies (2) the absence of material changes to market structures that would limit or otherwise negatively affect Exelon or Generation. Generation could also be affected by state laws, regulations, or initiatives to subsidize existing or new generation.
FERC’s requirements for market-based rate authority could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates.
The Registrants’ are highly regulated and could be negatively affected by regulatory and legislative actions (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation.
Generation’s consolidated financial statements are significantly affected by its sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates and Federal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity, and RPS. Legislative and regulatory efforts in Illinois, New York, and New Jersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through ZEC programs are or could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of Generation’s nuclear plants. See Note 3Regulatory Matters and Note 7Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers.
Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of
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energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
NRC actions could negatively affect the operations and profitability of Generation’s 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 capital expenditures or could result in increased operating or decommissioning costs. 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 and the timing of such a facility opening, will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse Generation for these costs.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to fully decommission its nuclear units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 19Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
The Registrants as users, owners, and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. PECO, BGE, and DPL, as operators of natural gas distribution systems, are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the Federal and state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses that the Registrants operate are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property
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contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Regulation for additional information.
The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).
The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1Significant Accounting Policies and Note 14Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of the Registrants. See ITEM 1. BUSINESS — Environmental Regulation — Renewable and Clean Energy Standards for additional information.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators, and advocacy groups are aware of Generation’s affiliation with the Utility Registrants 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 could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity, and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible
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to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs).
Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants).
The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material ones are summarized in Note 19Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue, or restrict existing business activities.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).
On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. Exelon and ComEd have cooperated fully, including by providing all information requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to civil penalties, sanctions, or other remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including, but not limited to, the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose
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revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
Operational Factors
The Registrants are subject to risks associated with climate change (All Registrants).
The Registrants periodically perform analyses to better understand how climate change could affect their facilities and operations. The Registrants primarily operate in the Midwest and East Coast of the United States, areas that historically have been prone to various types of severe weather events, such that the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, resulting in more intense, frequent and extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. In addition, changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations. Over time, the Registrants may need to make additional investments to protect facilities from physical climate-related risks and/or adapt to changes in operational requirements as a result of climate change.
The Registrants also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate change. To the extent additional GHG reduction regulation or legislation becomes effective at the Federal and/or state levels, the Registrants could incur costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements. To the extent such additional regulation or legislation does not become effective, the potential competitive advantage offered by Registrant’s low-carbon emission profile may be reduced. See ITEM 1. BUSINESS — Climate Change Mitigation.
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 nuclear generating units, significantly affect Generation’s results of operations. Lower capacity factors could decrease Generation’s revenues and increase operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease, and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs, and/or increased costs due to decreased generation capabilities.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation must shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments.
For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating
41

performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy. In addition, closure of generating plants owned by others, or extended interruptions of generating plants, or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy.
As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.8 billion limit for a single incident.
See Note 19Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs, and Federal and state regulatory requirements. The costs of such decommissioning may substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
Generation makes contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income, and the adverse impact to Exelon’s and Generation’s financial statements could be material. Any changes to the existing PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the investments held by Generation’s NDT funds are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent
42

company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.
See Note 10Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor, and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of the Registrants could be negatively affected, customer confidence in the Registrants or others in the industry could be diminished, or the Registrants could be subject to legal claims, loss of revenues, increased costs, or operations shutdown. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
The Utility Registrants' deployment of smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the system by third parties.
In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.
The Registrants’ employees, contractors, customers, and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants’ operations. As a result, employees,
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contractors, customers, and the general public are at some risk for serious injury, including loss of life. These 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, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security, and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could 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 Exelon's generating and transmission and distribution assets could be affected.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources for additional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission
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capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’ service areas.
The Registrants consolidated financial statements could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission, and distribution operations.
The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses, and entry into LNG. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the future. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
Risks Related to the Planned Separation (Exelon and Generation)
The planned separation is contingent upon regulatory approvals and satisfaction of other conditions and may not be completed in accordance with the expected plans or anticipated timeline, or at all, which could negatively affect Exelon’s and Generation’s consolidated financial statements.
Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The planned separation is subject to approval by the FERC, NRC and NYPSC. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. If the planned separation is not completed or is delayed, Exelon’s and Generation’s consolidated financial statements may be materially adversely affected, and the market price of Exelon’s common stock may be affected.
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The plan to separate into two publicly traded companies will involve significant time and expense, which could disrupt or adversely affect our business.
The planned separation is complex in nature, and unanticipated developments or changes, including challenges in executing the separation, could delay or prevent the completion of the proposed separation, or cause the separation to occur on terms or conditions that are different or less favorable than expected. Additionally, Exelon’s Board of Directors, in its sole and absolute discretion, may decide not to proceed with the separation at any time prior to the distribution date. The process of completing the proposed separation has been and is expected to continue to be time-consuming and involves significant costs and expenses.
The planned separation may not achieve some or all of the anticipated benefits and each separate company following the separation may underperform relative to Exelon’s expectations.
By separating the Utility Registrants and Generation, Exelon is creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus on their unique customer, market and community priorities. However, the planned separation may not provide such results on the scope or scale that Exelon anticipates, and Exelon and Generation may not realize the anticipated benefits of the planned separation. Failure to do so could have a material adverse effect on the financial statements of each separate company and their respective common stock price.
Following the planned separation, the companies anticipate to maintain investment grade credit ratings. Ratings are based upon assessments of multiple factors, including a company’s credit metrics as well as industry and macroeconomic changes and trends. If a rating agency were to downgrade the rating below investment grade, the separate companies’ borrowing costs would increase and their funding sources could decrease, which could have a material adverse effect on the financial statements of the affected company.
The common stock of the separately publicly traded companies following the separation may collectively trade at a value less than the price at which Exelon’s common stock might have traded had the separation not occurred.
There could be significant liability if the planned spin-off is determined to be a taxable transaction.
Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders under Sections 355 and 368 of the IRC. Exelon will seek a private letter ruling from the IRS regarding the tax-free nature of the transaction. Exelon will also seek from its tax advisors an opinion with respect to certain U.S. federal income tax consequences of the spin-off. If the planned spin-off ultimately is determined to be taxable, the spin-off could be treated as a taxable dividend to Exelon’s shareholders for U.S. federal income tax purposes, and Exelon’s shareholders could incur significant U.S. federal income tax liabilities. In addition, Exelon would recognize a taxable gain to the extent that the fair market value of the new company’s stock exceeds its tax basis in such stock on the date of the planned separation. Exelon will enter into a Tax Matters Agreement with the new company to address how post-separation issues will be managed between the companies, as well as which company is responsible for taxes imposed as a result of the planned separation, if any.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information on the planned separation.
ITEM 1B.UNRESOLVED STAFF COMMENTS
All Registrants
None.
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ITEM 2.PROPERTIES
Generation
The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2020:
Station(a)
LocationNo. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
Midwest
BraidwoodBraidwood, ILUraniumBase-load2,386 
ByronByron, ILUraniumBase-load2,347 (e)
LaSalleSeneca, ILUraniumBase-load2,320 
DresdenMorris, ILUraniumBase-load1,845 (e)
Quad CitiesCordova, IL75 UraniumBase-load1,403 (f)
ClintonClinton, ILUraniumBase-load1,080 
Michigan Wind 2Sanilac Co., MI50 51 (g)WindIntermittent46 (f)
BeebeGratiot Co., MI34 51 (g)WindIntermittent42 (f)
Michigan Wind 1Huron Co., MI46 51 (g)WindIntermittent35 (f)
Harvest 2Huron Co., MI33 51 (g)WindIntermittent30 (f)
HarvestHuron Co., MI32 51 (g)WindIntermittent27 (f)
Beebe 1BGratiot Co., MI21 51 (g)WindIntermittent26 (f)
City SolarChicago, ILSolarIntermittent
Solar OhioToledo, OHSolarIntermittent(h)
Blue BreezesFaribault Co., MNWindIntermittent
CP WindfarmFaribault Co., MN51 (g)WindIntermittent(f)
Southeast ChicagoChicago, ILGasPeaking296 (i)
Clinton Battery StorageBlanchester, OHEnergy StoragePeaking10 
Total Midwest11,911 
Mid-Atlantic
LimerickSanatoga, PAUraniumBase-load2,317 
Peach BottomDelta, PA50 UraniumBase-load1,324 (f)
SalemLower Alloways 
Creek Township, NJ
42.59 UraniumBase-load995 (f)
Calvert CliffsLusby, MD50.01 (j)UraniumBase-load895 (f)
ConowingoDarlington, MD11 HydroelectricBase-load572 
CriterionOakland, MD28 51 (g)WindIntermittent36 (f)
Fair WindGarrett County, MD12 WindIntermittent30 
Solar MCVarious, MD44 SolarIntermittent44 (h)
Fourmile RidgeGarrett County, MD16 51 (g)WindIntermittent20 (f)
Solar New Jersey 1Various, NJSolarIntermittent18 (h)
Solar New Jersey 2Various, NJSolarIntermittent11 (h)
Solar HorizonsEmmitsburg, MD51 (g)SolarIntermittent16 (f)
Solar MarylandVarious, MD11 SolarIntermittent(h)
Solar Maryland 2Various, MDSolarIntermittent(h)
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Station(a)
LocationNo. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
JBAB SolarDistrict of ColumbiaSolarIntermittent(h)
Gateway SolarBerlin, MDSolarIntermittent(h)
Constellation New EnergyGaithersburg, MDSolarIntermittent(h)
Solar FederalTrenton, NJSolarIntermittent(h)
Solar New Jersey 3Middle Township, NJ51 (g)SolarIntermittent(f)
Solar DCDistrict of ColumbiaSolarIntermittent(h)
Muddy RunDrumore, PAHydroelectricIntermediate1,070 
Eddystone 3, 4Eddystone, PAOil/GasPeaking760 
PerrymanAberdeen, MDOil/GasPeaking404 
CroydonWest Bristol, PAOilPeaking391 
Handsome LakeKennerdell, PAGasPeaking268 
RichmondPhiladelphia, PAOilPeaking98 
Philadelphia RoadBaltimore, MDOilPeaking61 
EddystoneEddystone, PAOilPeaking60 
DelawarePhiladelphia, PAOilPeaking56 
SouthwarkPhiladelphia, PAOilPeaking52 
FallsMorrisville, PAOilPeaking51 
MoserLower Pottsgrove Twp., PAOilPeaking51 
ChesterChester, PAOilPeaking39 
SchuylkillPhiladelphia, PAOilPeaking30 
SalemLower Alloways 
Creek Township, NJ
42.59 OilPeaking16 (f)
Total Mid-Atlantic9,729 
ERCOT
WhitetailWebb County, TX57 51 (g)WindIntermittent47 (f)
SenderoJim Hogg and Zapata County, TX39 51 (g)WindIntermittent40 (f)
Constellation Solar TexasVarious, TX11 SolarIntermittent13 (h)
Colorado Bend IIWharton, TXGasIntermediate1,143 
Wolf Hollow IIGranbury, TXGasIntermediate1,115 
Handley 3Fort Worth, TXGasIntermediate395 
Handley 4, 5Fort Worth, TXGasPeaking870 
Total ERCOT3,623 
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Station(a)
LocationNo. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
New York
Nine Mile PointScriba, NY50.01 (j)UraniumBase-load838 (f)
FitzPatrickScriba, NYUraniumBase-load842 
GinnaOntario, NY50.01 (j)UraniumBase-load288 (f)
Solar New YorkBethlehem, NYSolarIntermittent(h)
Total New York1,971 
Other
Antelope ValleyLancaster, CASolarIntermittent242 
BluestemBeaver County, OK60 51 (g)(k)WindIntermittent101 (f)
Shooting StarKiowa County, KS65 51 (g)WindIntermittent53 (f)
Albany Green EnergyAlbany, GA99 (l)BiomassBase-load50 (f)
Solar ArizonaVarious, AZ127 SolarIntermittent46 (h)
Bluegrass RidgeKing City, MO27 51 (g)WindIntermittent29 (f)
California PV Energy 2Various, CA89 SolarIntermittent27 (h)
ConceptionBarnard, MO24 51 (g)WindIntermittent26 (f)
Cow BranchRock Port, MO24 51 (g)WindIntermittent26 (f)
Solar Arizona 2Various, AZ56 SolarIntermittent34 (h)
California PV EnergyVarious, CA53 SolarIntermittent21 (h)
Mountain HomeGlenns Ferry, ID20 51 (g)WindIntermittent21 (f)
High MesaElmore Co., ID19 51 (g)WindIntermittent20 (f)
Echo 1Echo, OR21 50.49 (g)WindIntermittent17 (f)
Sacramento PV EnergySacramento, CA51 (g)SolarIntermittent30 (f)
CassiaBuhl, ID14 51 (g)WindIntermittent15 (f)
WildcatLovington, NM13 51 (g)WindIntermittent14 (f)
Echo 2Echo, OR10 51 (g)WindIntermittent10 (f)
Solar Georgia 2Various, GASolarIntermittent10 (h)
Tuana SpringsHagerman, ID51 (g)WindIntermittent(f)
Solar GeorgiaVarious, GA10 SolarIntermittent(h)
GreensburgGreensburg, KS10 51 (g)WindIntermittent(f)
Solar MassachusettsVarious, MA10 SolarIntermittent(h)
Outback SolarChristmas Valley, ORSolarIntermittent(h)
Echo 3Echo, OR50.49 (g)WindIntermittent(f)
Holyoke SolarVarious, MASolarIntermittent(h)
Three Mile CanyonBoardman, OR51 (g)WindIntermittent(f)
Loess HillsRock Port, MOWindIntermittent
California PV Energy 3Various, CA31 SolarIntermittent(h)
Denver Airport SolarDenver, CO51 (g)SolarIntermittent(f)
Solar Net MeteringUxbridge, MASolarIntermittent(h)
Solar ConnecticutVarious, CTSolarIntermittent(h)
Mystic 8, 9Charlestown, MAGasIntermediate1,413 (e)
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Station(a)
LocationNo. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
HillabeeAlexander City, 
AL
GasIntermediate753 
Mystic 7Charlestown, MAOil/GasIntermediate512 (m)
Wyman 4Yarmouth, ME5.9 OilIntermediate35 (f)
Grand PrairieAlberta, CanadaGasPeaking105 
West MedwayWest Medway, MAOilPeaking124 
West Medway IIWest Medway, MAOil/GasPeaking192 
FraminghamFramingham, MAOilPeaking31 
Mystic JetCharlestown, MAOilPeaking(m)
Total Other4,037 
Total31,271 
__________
(a)All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors.
(b)100%, unless otherwise indicated.
(c)Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(d)For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating.
(e)Generation has announced it will permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
(f)Net generation capacity is stated at proportionate ownership share.
(g)Reflects the prior sale of 49% of EGRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.
(h)On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation's solar business. The transaction is expected to be completed in the first half of 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
(i)Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2021.
(j)Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional information.
(k)EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.
(l)Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.
(m)Generation has plans to retire and cease plant operations in 2021.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.
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The Utility Registrants
The Utility Registrants' electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2020 were as follows:
VoltageCircuit Miles
(Volts)ComEdPECOBGEPepcoDPLACE
765,00090
500,000(a)
188(a)21610916(a)(a)
345,0002,676
230,000549358770472274
138,0002,2451355561586214
115,00071225
69,000177567667
___________
(a)    In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant - for additional information.
The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines:
Circuit MilesComEdPECOBGEPepcoDPLACE
Overhead35,37912,9679,1794,0826,0077,393
Underground32,3499,46317,6506,9496,3602,984
Gas
The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2020:
PECOBGEDPL
Transmission91528(a)
Distribution6,9467,4432,142
Service piping6,4496,3831,461
Total13,40413,9783,611
___________
(a)    DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.

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The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities:
RegistrantFacilityLocationStorage Capacity
(mmcf)
Send-out or Peaking Capacity
(mmcf/day)
PECOLNG FacilityWest Conshohocken, PA1,200160
PECOPropane Air PlantChester, PA10525
BGELNG FacilityBaltimore, MD1,056332
BGEPropane Air PlantBaltimore, MD55085
DPLLNG FacilityWilmington, DE25025
PECO, BGE, and DPL also own 30, 30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively.
First Mortgage and Insurance
The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of their respective Mortgages under which their respective First Mortgage Bonds are issued. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are 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 in the consolidated financial condition or results of operations of the Utility Registrants.

Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.



ITEM 3.LEGAL PROCEEDINGS
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
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ITEM 4.MINE SAFETY DISCLOSURES
All Registrants
Not Applicable to the Registrants.
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PART II
(Dollars in millions except per share data, unless otherwise noted)
ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Exelon
Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2021, there were 976,337,799 shares of common stock outstanding and approximately 91,240 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2016 through 2020.
This performance chart assumes:
$100 invested on December 31, 2015 in Exelon common stock, the S&P 500 Stock Index, and the S&P Utility Index; and
All dividends are reinvested.
exc-20201231_g1.jpg
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Value of Investment at December 31,
201520162017201820192020
Exelon Corporation$100$132.81$152.79$180.80$188.53$181.20
S&P 500$100$111.96$136.40$130.42$171.49$203.04
S&P Utilities$100$116.29$130.36$135.72$171.48$172.31
Generation
As of January 31, 2021, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2021, there were 127,021,370 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2021, in addition to Exelon, there were 286 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2021, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2021, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2021, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2021, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2021, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2021, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its
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guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of $0.3825 per share.
At December 31, 2020, Exelon had retained earnings of $16,735 million, including Generation’s undistributed earnings of $2,805 million, ComEd’s retained earnings of $1,456 million consisting of retained earnings appropriated for future dividends of $3,095 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,519 million, BGE’s retained earnings of $1,879 million, and PHI's undistributed losses of $68 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2020 and 2019:
20202019
(per share)Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Exelon$0.3825 $0.3825 $0.3825 $0.3825 $0.3625 $0.3625 $0.3625 $0.3625 
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The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common dividend payments:
20202019
(in millions)4th
Quarter
3rd
Quarter
2nd
Quarter
1st
Quarter
4th
Quarter
3rd
Quarter
2nd
Quarter
1st
Quarter
Generation$328 $469 $469 $468 $225 $225 $224 $225 
ComEd126 124 124 125 128 126 127 127 
PECO85 85 85 85 90 88 90 90 
BGE60 62 62 62 55 57 56 56 
PHI102 183 134 134 97 213 88 128 
Pepco58 73 73 28 40 101 48 24 
DPL42 33 14 52 34 35 29 41 
ACE76 12 23 24 76 12 12 
First Quarter 2021 Dividend
On February 21, 2021, Exelon's Board of Directors declared a regular quarterly dividend of $0.3825 per share on Exelon’s common stock for the first quarter of 2021. The dividend is payable on Monday, March 15, 2021, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, March 8, 2021.
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Item 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2020 compared to the year ended December 31, 2019, and is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the year ended December 31, 2019 compared to the year ended December 31, 2018, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2019 Form 10-K, which was filed with the SEC on February 11, 2020.
COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on their employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic.
The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.
There were no changes in internal control over financial reporting in 2020 as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information.
Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas at Generation and the Utility Registrants, which has resulted in a decrease in operating revenues.
As a result of COVID-19, Generation temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily ceased new late payment fees for all retail customers from March to May of 2020. Starting in March of 2020, the Utility Registrants also temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on such measures at the Utility Registrants. At Generation, such measures resulted in an increase in credit loss expense. ComEd and ACE recorded regulatory assets for the incremental credit loss expense based on existing mechanisms. BGE, PECO, Pepco, and DPL also recorded regulatory assets for substantially all the incremental credit loss expense incurred in 2020. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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Generation and the Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees. At Generation and PECO, such costs are recorded as Operating and maintenance expense and are excluded from Adjusted (non-GAAP) Operating Earnings. At ComEd, BGE, Pepco, DPL, and ACE, such costs are primarily recorded as regulatory assets. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The estimated impact to Generation’s and the Utility Registrants’ Net income is approximately $170 million and $75 million for the year ended December 31, 2020, respectively.
To offset the unfavorable impacts from COVID-19, the Registrants identified approximately $250 million in cost savings across Generation and the Utility Registrants in 2020. The cost savings achieved in 2020 were higher than originally anticipated.
The Registrants rely on the capital markets for publicly offered debt as well as the commercial paper markets to meet their financial commitments and short-term liquidity needs. As a result of the disruptions in the commercial paper markets in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper, which Generation repaid on April 3, 2020. Generation also entered into two short-term loan agreements in March of 2020 for an aggregate of $500 million. On April 8, 2020, Generation received approximately $500 million in cash after entering into an accounts receivable financing arrangement. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility to be used as an additional source of short-term liquidity. In addition, the Registrants issued long-term debt of $5.3 billion and were able to successfully complete their planned long-term debt issuances in 2020. See Liquidity and Capital Resources, Note 17 — Debt and Credit Agreements, and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 as a result of COVID-19. See Note 12 — Asset Impairments for additional information related to other impairment assessments in the third quarter of 2020. Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be material.
This is an evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The extent to which COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around the world and future developments, which are highly uncertain and cannot be predicted at this time.

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Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year ended December 31, 2020 compared to the same period in 2019. For additional information regarding the financial results for the years ended December 31, 2020 and 2019 see the discussions of Results of Operations by Registrant.
20202019(Unfavorable) Favorable Variance
Exelon$1,963 $2,936 $(973)
Generation589 1,125 (536)
ComEd438 688 (250)
PECO447 528 (81)
BGE349 360 (11)
PHI495 477 18 
Pepco266 243 23 
DPL125 147 (22)
ACE112 99 13 
Other(a)
(355)(242)(113)
__________
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income attributable to common shareholders decreased by $973 million and diluted earnings per average common share decreased to $2.01 in 2020 from $3.01 in 2019 primarily due to:
One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation and amortization due to the early retirement of TMI in September 2019;
Impairment of the New England asset group;

Payments that ComEd made under the Deferred Prosecution Agreement. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;

Lower capacity revenue;

Reduction in load due to COVID-19 at Generation;

Lower realized energy prices;
Higher nuclear outage days;
Impact of Generation's annual update to the nuclear ARO for Non-Regulatory Agreement Units;
Lower net unrealized and realized gains on NDT funds;
COVID-19 direct costs;
Lower electric distribution earnings from lower allowed ROE due to a decrease in treasury rates, partially offset by higher rate base at ComEd;
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Higher storm costs related to the June 2020 and August 2020 storms at PECO, net of tax repairs, and related to the August 2020 storm at DPL;

Unfavorable weather conditions at PECO, DPL Delaware, and ACE; and

A net increase in depreciation and amortization expense due to ongoing capital expenditures at PECO, BGE, Pepco, DPL, and ACE, partially offset at Generation due to the impact of extending the operating license at Peach Bottom.

The decreases were partially offset by;
Higher mark-to-market gains;
Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter and were fair valued based on quoted market prices of the stocks as of December 31, 2020;
Lower operating and maintenance expense at Generation primarily due to previous cost management programs, lower contracting costs, and lower travel costs, partially offset by lower NEIL insurance distributions;
Lower nuclear fuel costs;
A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and development activities recorded in the fourth quarter of 2019 at Generation; and
Regulatory rate increases at BGE, DPL, and ACE.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2020 as compared to 2019: 
For the Years Ended December 31,
20202019
(All amounts in millions after tax)Earnings per
Diluted Share
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,963 $2.01 $2,936 $3.01 
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $73 and $66, respectively)(213)(0.22)197 0.20 
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $278 and $269, respectively)(a)
(256)(0.26)(299)(0.31)
Asset Impairments (net of taxes of $135 and $56, respectively)(b)
396 0.41 123 0.13 
Plant Retirements and Divestitures (net of taxes of $244 and $9, respectively)(c)
718 0.74 118 0.12 
Cost Management Program (net of taxes of $14 and $17, respectively)(d)
45 0.05 51 0.05 
Litigation Settlement Gain (net of taxes of $7)— — (19)(0.02)
Asset Retirement Obligation (net of taxes of $16 and $9, respectively)(e)
48 0.05 (84)(0.09)
Change in Environmental Liabilities (net of taxes of $6 and $8, respectively)18 0.02 20 0.02 
COVID-19 Direct Costs (net of taxes of $19)(f)
50 0.05 — — 
Deferred Prosecution Agreement Payments (net of taxes of $0)(g)
200 0.20 — — 
Acquisition Related Costs (net of taxes of $1)(h)
— — — 
ERP System Implementation Costs (net of taxes of $1)(i)
— — — 
Income Tax-Related Adjustments (entire amount represents tax expense)(j)
71 0.07 0.01 
Noncontrolling Interests (net of taxes of $19 and $26, respectively)(k)
103 0.11 90 0.09 
Adjusted (non-GAAP) Operating Earnings$3,149 $3.22 $3,139 $3.22 
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2020 and 2019 ranged from 26.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 52.1% and 47.3% for the years ended December 31, 2020 and 2019, respectively.

(a)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(b)In 2020, reflects an impairment at ComEd in the second quarter of 2020 related to the acquisition of transmission assets and an impairment of the New England asset group in the third quarter of 2020. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such impairment net of noncontrolling interest is $0.02.
(c)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO, and a gain on the sale of certain wind assets.
(d)Primarily represents reorganization and severance costs related to cost management programs.
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(e)Reflects an adjustment to Generation's nuclear ARO for Non-Regulatory Agreement Units resulting from the annual update.
(f)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(g)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.
(h)Reflects costs related to the acquisition of EDF's interest in CENG.
(i)Reflects costs related to a multi-year ERP system implementation.
(j)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(k)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.
Significant 2020 Transactions and Developments
Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to fuel power plants, and dramatically increased wholesale power and gas prices.
Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result. Exelon expects to offset between $410 million and $490 million of this impact primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Agreement for Sale of Generation’s Solar Business
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the United States, for a purchase price of $810 million. Completion of the transaction is expected to occur in the first half of 2021. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
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Early Retirement of Generation Facilities
In August 2020, Generation announced that it intends to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million impairment of its New England asset group and one-time non-cash charges for Byron, Dresden, and Mystic related to materials and supplies inventory reserve adjustments, employee-related costs, and construction work-in-progress impairments, among other items. In addition, there will be ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel. Such ongoing charges are excluded from Adjusted (non-GAAP) Operating Earnings.
The following table summarizes the incremental expense recorded for the year ended December 31, 2020 and the estimated amounts of incremental expense expected to be incurred through the retirement dates.
Actual
Projected(a)
Income statement expense (pre-tax)20202021202220232024
Depreciation and amortization
     Accelerated depreciation(b)
$921 $2,070 $110 $120 $50 
     Accelerated nuclear fuel amortization60 170 — — — 
Operating and maintenance
     One-time charges277 30 10 — 20 
     Other charges(c)
35 10 10 10 
     Contractual offset(d)
(364)(475)— — — 
Total$929 $1,805 $130 $130 $75 
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Reflects primarily the net impacts associated with the remeasurement of the ARO for Dresden. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
(d)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Deferred Prosecution Agreement
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into ComEd’s lobbying activities in the State of Illinois. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to customers, and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. See Note 19 — Commitments and Contingencies for additional information.
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Utility Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2020. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement (Decrease) IncreaseApproved Revenue Requirement (Decrease) IncreaseApproved ROEApproval DateRate Effective Date
ComEd - IllinoisApril 8, 2019Electric$(6)$(17)8.91 %December 4, 2019January 1, 2020
ComEd - IllinoisApril 16, 2020Electric(11)(14)8.38 %December 9, 2020January 1, 2021
BGE - MarylandMay 15, 2020 (amended September 11, 2020)Electric137 81 9.50 %December 16, 2020January 1, 2021
Natural Gas91 21 9.65 %
DPL - MarylandDecember 5, 2019 (amended April 23, 2020)Electric17 12 9.60 %July 14, 2020July 16, 2020
DPL - DelawareFebruary 21, 2020 (amended October 9, 2020)Natural Gas9.60 %January 6, 2021September 21, 2020
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Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
PECO - PennsylvaniaSeptember 30, 2020Natural Gas$69 10.95 %Second quarter of 2021
Pepco - District of ColumbiaMay 30, 2019 (amended June 1, 2020)Electric136 9.7 %Second quarter of 2021
Pepco - MarylandOctober 26, 2020Electric110 10.2 %Second quarter of 2021
DPL - DelawareMarch 6, 2020 (amended February 2, 2021)Electric23 10.3 %Third quarter of 2021
ACE - New JerseyDecember 9, 2020Electric67 10.3 %Fourth quarter of 2021
Transmission Formula Rates
The following total increases/(decreases) were included in the Utility Registrants' 2020 annual electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
RegistrantInitial Revenue Requirement Increase/(Decrease)Annual Reconciliation DecreaseTotal Revenue Requirement Increase/(Decrease)Allowed Return on Rate BaseAllowed ROE
ComEd$18 $(4)$14 8.17 %11.50 %
PECO(28)(23)7.47 %10.35 %
BGE16 (3)7.26 %10.50 %
Pepco(46)(44)7.81 %10.50 %
DPL(4)(40)(44)7.20 %10.50 %
ACE(25)(20)7.40 %10.50 %
Sales of Customer Accounts Receivable
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by Generation, entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain customer accounts receivables. Generation received approximately $500 million of cash in accordance with the initial sale of approximately $1.2 billion receivables. See Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Exelon’s Strategy and Outlook
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
In 2021, the businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring timely recovery on investments to enable customer benefits, supporting enactment of clean energy policies, and continued commitment to corporate responsibility.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest
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reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid 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 energy solutions and reliable, clean, and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and match supply to customers. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The Utility Registrants anticipate investing approximately $27 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $15 billion by the end of 2024. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that match supply to customers as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly
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over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce ("DOC") seeking relief under Section 232 of the Trade Expansion Act of 1962 from imports of uranium products, alleging that these imports threaten national security.
The United States Nuclear Fuel Working Group ("Working Group") report was made public on April 23, 2020. The Working Group report states that nuclear power is intrinsically tied to national security, and promises that the U.S. government will take bold actions to strengthen all parts of the nuclear fuel industry in the U.S. It recommends the Agreement Suspending the Antidumping Investigation on Uranium from the Russian Federation (the “Russian Suspension Agreement” or "RSA") be extended and to consider reducing the amount of Russian imports of nuclear fuel. The Russian Suspension Agreement is the historical resolution of a 1991 DOC investigation that found that the Russians had been selling or “dumping” cheap uranium products into the U.S. The RSA has been amended several times in the intervening years to allow Russia to supply limited amounts of uranium products into the U.S. It was set to expire at the end of 2020, but was amended on October 5, 2020 to extend for another 20 years.
The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress, and or regulatory bodies. Exelon and Generation cannot currently predict the outcome of all of the policy changes recommended by the Working Group.
Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps
On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Load growth at the Utility Registrants is driven by recovery from COVID-19 impacts. ComEd and PECO are projecting modest growth in load of 2.5% and 1.8%, respectively, in 2021 as compared to reduced load in 2020. BGE, Pepco, DPL, and ACE are projecting slower growth as prolonged COVID-19 impacts decrease load by (2.0)%, (0.8)%, (0.9)%, and (2.4)%, respectively, in 2021 compared to 2020.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 2021. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.
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Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of Generation’s uranium concentrate requirements from 2021 through 2025 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s consolidated financial statements.
See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Other Legislative and Regulatory Developments
Illinois Clean Energy Progress Act
On March 14, 2019, the Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM’s base residual auction process, while utilizing the FRR provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation’s nuclear plants in Illinois, or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders in 2019 and 2020, including renewable resource developers, environmental advocates, and coal-fueled generators. Lawmakers focused their efforts on understanding all of the various legislative proposals with the goal of developing a single comprehensive energy package for ultimate consideration by the General Assembly and Governor Pritzker. Due to the COVID-19 pandemic, the legislative calendar during 2020 was severely curtailed stalling progress on comprehensive energy legislation. The fall 2020 veto session was cancelled. The next opportunity for the General Assembly to consider development of comprehensive energy legislation appears to come during the 2021 spring legislative session. Exelon and Generation will work with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Nuclear Powers Act of 2019
On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026.  Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently
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uncertain and that may change in subsequent periods. Additional information of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation’s ARO associated with decommissioning its nuclear units was $11.9 billion at December 31, 2020. The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.
As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information becomes available and could change the timing of plant retirements and the 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 for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:
Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.
Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. 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 scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which assumes the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT fund at the time of shutdown.
The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended
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60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. 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. Generation currently assumes DOE will begin accepting SNF in 2035. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding the estimated date when DOE will begin accepting SNF, see Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. Generation initially recognizes an ARO at fair value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation’s future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately $11.9 billion to approximately $15.0 billion.
The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO (dollars in millions):
Change in the CARFR applied to the annual ARO update(Decrease) Increase to ARO at December 31, 2020
2019 CARFR rather than the 2020 CARFR$(370)
2020 CARFR increased by 50 basis points(390)
2020 CARFR decreased by 50 basis points490 
ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact to the ARO of a change in any one of these assumptions is highly dependent on how the other assumptions may correspondingly change.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):
Change in ARO AssumptionIncrease to ARO at December 31, 2020
Cost escalation studies
Uniform increase in escalation rates of 50 basis points$2,560 
Probabilistic cash flow models
Increase the estimated costs to decommission the nuclear plants by 10 percent1,050 
Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a)
610 
Shorten each unit's probability weighted operating life assumption by 10 percent(b)
1,690 
Extend the estimated date for DOE acceptance of SNF to 2040280 
__________
(a)Excludes any sites in which management has committed to a specific decommissioning approach.
(b)Excludes any retired sites.
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See Note 1 — Significant Accounting Policies, Note 7 — Early Plant Retirements and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.
Goodwill (Exelon, ComEd, and PHI)
As of December 31, 2020, Exelon’s $6.7 billion carrying amount of goodwill consists primarily of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed.
Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt.
While the 2020 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.
See Note 1 — Significant Accounting Policies and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized Energy Contract Assets and Liabilities (Exelon, Generation, and PHI)
Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon acquired as part of the PHI merger. The initial amount recorded represents the fair value of the contracts at the time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities is recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. See Note 3 — Regulatory Matters and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Impairment of Long-Lived Assets (All Registrants)
All Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology, plans to dispose of a long-lived asset
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significantly before the end of its useful life, and financial distress of a third party for assets contracted with them on a long-term basis, among others.
The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of 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 the geographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets or liabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables). For such assets the financial viability of the third party, including the impact of bankruptcy on the contract, may be a significant assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market discount rates. Events and circumstances often do not occur as expected resulting in differences between prospective financial information and actual results, which may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial and industry sources.
See Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment assessments.
Depreciable Lives of Property, Plant, and Equipment (All Registrants)
The Registrants have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, composite, or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally completed every five years, or more frequently if required by a rate regulator or if an event, regulatory action, or change in retirement patterns indicate an update is necessary.
For the Utility Registrants, depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Utility Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.
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PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.
At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material unfavorable impact on Exelon’s and Generation’s future results of operations. See Note 7 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants.
Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations.
Pension and OPEB plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, and hedge funds.
Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.
Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates.
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Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant (dollars in millions):
Actual Assumption
Actuarial AssumptionPensionOPEBChange in
Assumption
PensionOPEBTotal
Change in 2020 cost:
Discount rate(a)
3.34%3.31%0.5%$(52)$(14)$(66)
3.34%3.31%(0.5)%70 15 85 
EROA7.00%6.69%0.5%(91)(12)(103)
7.00%6.69%(0.5)%91 12 103 
Change in benefit obligation at December 31, 2020:
Discount rate(a)
2.58%2.51%0.5%(1,410)(268)(1,678)
2.58%2.51%(0.5)%1,631 309 1,940 
__________
(a)In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.
See Note 1Significant Accounting Policies and Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans.
Regulatory Accounting (Exelon and Utility Registrants)
For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, Exelon and the Utility Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income.
The following table illustrates the gains (losses) that could result from the elimination of regulatory assets and liabilities and charges against OCI (dollars in millions before taxes) related to deferred costs associated with Exelon's pension and OPEB plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets:
December 31, 2020ExelonComEdPECOBGEPHIPepcoDPLACE
Gain (loss)$79 $4,664 $(177)$490 $(798)$(94)$260 $(152)
Charge against OCI(a)
$3,984 $— $— $— $— $— $— $— 
___________
(a)Exelon's charge against OCI (before taxes) consists of up to $2.7 billion, $481 million, $193 million, $387 million, $188 million, and $91 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of $(36) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.
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See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon and the Utility Registrants.
For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund 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 each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.
Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.
Accounting for Derivative Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk, and interest rate risk related to ongoing business operations. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlyings and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance.
All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives entered into for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given likelihood of recovering the associated costs through customer rates.
NPNS. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as NPNS transactions, which are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. Contracts that qualify for the NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreements, all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives, and certain Pepco, DPL, and ACE full requirement contracts qualify for and are accounted for under the NPNS.
Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.
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As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.
Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges. The price quotations reflect the average of the bid-ask mid-point from markets that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The Registrant’s derivatives are traded predominately at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the model inputs are generally observable. Such instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, including both historical and current market data in its assessment of nonperformance risk, including credit risk. The impacts of nonperformance and credit risk to date have generally not been material to the financial statements.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 18 — Fair Value of Financial Assets and Liabilities and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.
Taxation (All Registrants)
Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
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Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work and changes in technology, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact in the Registrants’ consolidated financial statements.

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Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, Derivative and ARP guidance to recognize revenue as discussed in more detail below.
Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with ISOs.
The determination of Generation’s and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.
Alternative Revenue Program Accounting. Certain of the Utility Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants’ formula rate mechanisms and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates
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that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Allowance for Credit Losses on Customer Accounts Receivable (Utility Registrants)
Utility Registrants estimate the allowance for credit losses on customer receivables by applying loss rates developed specifically for each company based on historical loss experience, current conditions, and forward-looking risk factors to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU regulations.


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Results of Operations by Registrant
Results of Operations—Generation
Generation’s Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance.
20202019(Unfavorable) Favorable Variance
Operating revenues$17,603 $18,924 $(1,321)
Purchased power and fuel expense9,585 10,856 1,271 
Revenues net of purchased power
and fuel expense
8,018 8,068 (50)
Other operating expenses
Operating and maintenance5,168 4,718 (450)
Depreciation and amortization2,123 1,535 (588)
Taxes other than income taxes482 519 37 
Total other operating expenses7,773 6,772 (1,001)
Gain on sales of assets and businesses11 27 (16)
Operating income256 1,323 (1,067)
Other income and (deductions)
Interest expense(357)(429)72 
Other, net937 1,023 (86)
Total other income and (deductions)580 594 (14)
Income before income taxes836 1,917 (1,081)
Income taxes249 516 267 
Equity in losses of unconsolidated affiliates(8)(184)176 
Net income579 1,217 (638)
Net (loss) income attributable to noncontrolling interests(10)92 (102)
Net income attributable to membership interest$589 $1,125 $(536)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income attributable to membership interest decreased by $536 million primarily due to:
One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation and amortization due to the early retirement of TMI in September 2019;
Impairment of the New England asset group;
Lower capacity revenue;
Reduction in load due to COVID-19;
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Lower realized energy prices;
Higher nuclear outage days;
Impact of Generation's annual update to the nuclear ARO for Non-regulatory Agreement Units;
Lower net unrealized and realized gains on NDT funds;
COVID-19 direct costs; and
The decreases were partially offset by:
Higher mark-to-market gains;
Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the stocks as of December 31, 2020;
Lower operating and maintenance expense primarily due to previous cost management programs, lower contracting costs, and lower travel costs partially offset by lower NEIL insurance distributions;
Lower nuclear fuel costs;
Lower depreciation and amortization expense due to the impact of extending the operating license at Peach Bottom;

A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and development activities recorded in the fourth quarter of 2019.

Revenues 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 different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 5Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy,
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and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.
For the years ended December 31, 2020 compared to 2019, RNF by region were as follows. See Note 5 - Segment Information of the Combined Notes to the Consolidated Financial Statements for additional information on Purchase power and fuel expense for Generation’s reportable segments.
2020 vs. 2019
20202019Variance% Change
Mid-Atlantic(a)
$2,204 $2,655 $(451)(17.0)%
Midwest(b)
2,902 2,962 (60)(2.0)%
New York997 1,094 (97)(8.9)%
ERCOT426 308 118 38.3 %
Other Power Regions665 620 45 7.3 %
Total electric revenues net of purchased power and fuel expense7,194 7,639 (445)(5.8)%
Mark-to-market gains (losses)295 (215)510 237.2 %
Other529 644 (115)(17.9)%
Total revenue net of purchased power and fuel expense$8,018 $8,068 $(50)(0.6)%
__________
(a)Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE.
(b)Includes results of transactions with ComEd.

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Generation’s supply sources by region are summarized below:
2020 vs. 2019
Supply Source (GWhs)20202019Variance% Change
Nuclear Generation(a)
Mid-Atlantic52,202 58,347 (6,145)(10.5)%
Midwest96,322 94,890 1,432 1.5 %
New York26,561 28,088 (1,527)(5.4)%
Total Nuclear Generation175,085 181,325 (6,240)(3.4)%
Fossil and Renewables
Mid-Atlantic2,206 2,884 (678)(23.5)%
Midwest1,240 1,374 (134)(9.8)%
New York(1)(20.0)%
ERCOT11,982 13,572 (1,590)(11.7)%
Other Power Regions11,121 11,476 (355)(3.1)%
Total Fossil and Renewables26,553 29,311 (2,758)(9.4)%
Purchased Power
Mid-Atlantic
22,487 14,790 7,697 52.0 %
Midwest770 1,424 (654)(45.9)%
ERCOT5,636 4,821 815 16.9 %
Other Power Regions51,079 48,673 2,406 4.9 %
Total Purchased Power79,972 69,708 10,264 14.7 %
Total Supply/Sales by Region(c)
Mid-Atlantic(b)
76,895 76,021 874 1.1 %
Midwest(b)
98,332 97,688 644 0.7 %
New York26,565 28,093 (1,528)(5.4)%
ERCOT17,618 18,393 (775)(4.2)%
Other Power Regions62,200 60,149 2,051 3.4 %
Total Supply/Sales by Region281,610 280,344 1,266 0.5 %
__________
(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).
(b)Includes affiliate sales to PECO, BGE, Pepco, DPL, and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(c)Reflects a decrease in load due to COVID-19.

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For the years ended December 31, 2020 compared to 2019 changes in RNF by region were as follows:
2020 vs. 2019
(Decrease)/IncreaseDescription
Mid-Atlantic$(451)• decreased revenue due to the permanent cease of generation operations at TMI in the third quarter of 2019
• decreased capacity revenues
• lower realized energy prices, partially offset by
• increase in newly contracted load offset by impacts of COVID-19
• increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019
Midwest(60)• decreased capacity revenues
• lower realized energy prices
• decreased load due to COVID-19 offset by an increase in total ISO sales, partially offset by
• decreased nuclear outage days
New York(97)• increased nuclear outage days
• decreased ZEC revenues due to increased outage days
• lower realized energy prices
• decreased load due to COVID-19 offset by newly contracted load, partially offset by
• increased capacity revenues
ERCOT118 • lower procurement costs for owned and contracted assets
• higher portfolio optimization, partially offset by
• lower realized energy prices
Other Power Regions45 • higher portfolio optimization
• increase in newly contracted load offset by impacts of COVID-19, partially offset by
• decreased capacity revenues
• lower realized energy prices
Mark-to-market(a)
510 • gains on economic hedging activities of $295 million in 2020 compared to losses of $215 million in 2019
Other(115)• increase in accelerated nuclear fuel amortization associated with announced early plant retirements • decreased revenue related to the energy efficiency business
Total$(50)
__________
(a)See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
20202019
Nuclear fleet capacity factor95.4 %95.7 %
Refueling outage days260 209 
Non-refueling outage days19 51 
The changes in Operating and maintenance expense, consisted of the following:
2020 vs. 2019
Increase (Decrease)
Asset Impairments$499 
ARO update125 
Nuclear refueling outage costs, including the co-owned Salem plants60 
Insurance52 
COVID-19 direct costs46 
Litigation settlements26 
Change in environmental liabilities18 
Credit loss expense(a)
16 
Accretion expense14 
Plant retirements and divestitures(8)
Pension and non-pension postretirement benefits expense(19)
Corporate allocations(35)
Travel costs(38)
Other(71)
Labor, other benefits, contracting, and materials(b)
(235)
Total increase$450 
__________
(a)Increased credit loss expense including impacts from COVID-19.
(b)Primarily reflects decreased costs related to the permanent cease of generation operations at TMI, lower labor costs resulting from previous cost management programs, and decreased contracting costs.
Depreciation and amortization expense for the year ended December 31, 2020 compared to the same period in 2019 increased primarily due to the accelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities, partially offset by the permanent cease of generation operations at TMI.
Taxes other than income taxes for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to decreased sales and power usage.
Gain on sales of assets and businesses for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to Generation's gain on sale of certain wind assets in 2019 partially offset by the loss on sale of Oyster Creek.
Other, net for the year ended December 31, 2020 compared to the same period in 2019 decreased due to activity associated with NDT funds as described in the table below.
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20202019
Net unrealized gains on NDT funds(a)
$391 $411 
Net realized gains on sale of NDT funds(a)
70 253 
Interest and dividend income on NDT funds(a)
90 110 
Contractual elimination of income tax expense(b)
180 216 
Unrealized gains from equity investments(c)
186 — 
Other20 33 
Total other, net$937 $1,023 
__________
(a)Unrealized gains, realized gains, and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units.
(b)Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement Units.
(c)Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair valued based on quoted market prices of the stocks as of December 31, 2020.
Interest Expense for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to the redemption of long-term debt in 2020.
Effective income tax rates were 29.8% and 26.9% for the years ended December 31, 2020 and 2019, respectively. The change in 2020 is primarily related to one-time income tax settlements partially offset by the absence of research and development refund claims. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Equity in losses of unconsolidated affiliates for the year ended December 31, 2020 compared to the same period in 2019 increased primarily due to the impairment of equity method investments in certain distributed energy companies in the third quarter of 2019.
Net income attributable to noncontrolling interests for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to lower unrealized losses on NDT fund investments for CENG.

87

Results of Operations—ComEd
20202019Favorable (Unfavorable) Variance
Operating revenues$5,904 $5,747 $157 
Operating expenses
Purchased power expense1,998 1,941 (57)
Operating and maintenance1,520 1,305 (215)
Depreciation and amortization1,133 1,033 (100)
Taxes other than income taxes299 301 
Total operating expenses4,950 4,580 (370)
Gain on sales of assets— (4)
Operating income954 1,171 (217)
Other income and (deductions)
Interest expense, net(382)(359)(23)
Other, net43 39 
Total other income and (deductions)(339)(320)(19)
Income before income taxes615 851 (236)
Income taxes177 163 (14)
Net income$438 $688 $(250)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income decreased by $250 million primarily due to payments that ComEd made under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and lower allowed electric distribution ROE due to a decrease in treasury rates, partially offset by higher electric distribution formula rate earnings (reflecting the impacts of higher rate base). See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.
The changes in Operating revenues consisted of the following:
2020 vs. 2019
Increase
Energy efficiency$37 
Electric distribution36 
Transmission
Other29
104 
Regulatory required programs53
Total increase
$157 

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA.
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Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the year ended December 31, 2020, as compared to the same period in 2019, primarily due to increased regulatory asset amortization which is fully recoverable. See Depreciation and amortization expense discussions below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. During the year ended December 31, 2020, as compared to the same period in 2019, electric distribution revenue increased due to the impact of higher rate base and higher fully recoverable costs, offset by lower allowed ROE due to a decrease in treasury rates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. During the year ended December 31, 2020, as compared to the same period in 2019, transmission revenues remained relatively consistent. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. The increase in Other revenue for the year ended December 31, 2020, as compared to the same period in 2019, primarily reflects mutual assistance revenues associated with storm restoration efforts.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC, and REC procurement. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase of $57 million for the year ended December 31, 2020, as compared to the same period in 2019, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.
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The changes in Operating and maintenance expense consisted of the following:

2020 vs. 2019
Increase (Decrease)
Deferred Prosecution Agreement payments(a)
$200 
BSC costs20 
Labor, other benefits, contracting, and materials
Pension and non-pension postretirement benefits expense
Storm-related costs(b)
(12)
Other(c)
(4)
216 
Regulatory required programs(d)
(1)
Total increase
$215 
__________
(a)See Note 19 Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
(b)For the year ended December 31, 2020, the decrease primarily reflects lower storm costs as a result of the August 2020 storm costs being reclassified to a regulatory asset.
(c)For the year ended December 31, 2020, the decrease primarily reflects lower travel costs offset by an impairment charge related to acquisition of transmission assets.
(d)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.
The changes in Depreciation and amortization expense consisted of the following:

2020 vs. 2019
Increase
Regulatory asset amortization(a)
$64 
Depreciation and amortization expense(b)
36 
Total increase$100 
__________
(a)Includes amortization of ComEd's energy efficiency formula rate regulatory asset and amortization related to the August 2020 storm regulatory asset.
(b)Reflects ongoing capital expenditures.
Interest Expense, net increased $23 million for the year ended December 31, 2020, as compared to the same period in 2019, primarily due to the issuance of debt in February 2020.
Effective income tax rates for the years ended December 31, 2020 and 2019, were 28.8% and 19.2%, respectively. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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Results of Operations—PECO
20202019(Unfavorable) Favorable Variance
Operating revenues$3,058 $3,100 $(42)
Operating expenses
Purchased power and fuel expense1,018 1,029 11 
Operating and maintenance975 861 (114)
Depreciation and amortization347 333 (14)
Taxes other than income taxes172 165 (7)
Total operating expenses2,512 2,388 (124)
Gain on sales of assets— (1)
Operating income546 713 (167)
Other income and (deductions)
Interest expense, net(147)(136)(11)
Other, net18 16 
Total other income and (deductions)(129)(120)(9)
Income before income taxes417 593 (176)
Income taxes(30)65 95 
Net income$447 $528 $(81)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income decreased by $81 million primarily due to unfavorable weather conditions, higher storm costs due to the June and August 2020 storms net of tax repairs, increased depreciation and amortization expense, and increased interest expense, partially offset by favorable volume and an increase in the tax repairs deduction.
The changes in Operating revenues consisted of the following:
2020 vs. 2019
(Decrease) Increase
ElectricGasTotal
Weather$(29)$(21)$(50)
Volume12 (3)
Pricing
Transmission11 — 11 
Other(7)(1)(8)
(11)(19)(30)
Regulatory required programs65 (77)(12)
Total increase (decrease)$54 $(96)$(42)
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2020 compared to the same period in 2019, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions 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. The changes in heating and cooling degree days in PECO’s service territory for the years ended December 31, 2020 compared to the same period in 2019 and normal weather consisted of the following:
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 For the Years Ended December 31, % Change
Heating and Cooling Degree-Days20202019Normal2020 vs. 20192019 vs. Normal
Heating Degree-Days3,959 4,307 4,437 (8.1)%(10.8)%
Cooling Degree-Days1,521 1,610 1,423 (5.5)%6.9 %
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2020 compared to the same period in 2019, increased due to an increase in usage for residential customers during COVID-19 further increased by customer growth. Natural gas volume for the year ended December 31, 2020 compared to the same period in 2019, decreased on a net basis due to a decrease in usage for the commercial and industrial natural gas classes during COVID-19.
Electric Retail Deliveries to Customers (in GWhs)20202019% Change 2020 vs. 2019
Weather - Normal % Change(b)
Retail Deliveries(a)
Residential14,041 13,650 2.9 %5.6 %
Small commercial & industrial7,210 7,983 (9.7)%(8.2)%
Large commercial & industrial13,669 14,958 (8.6)%(8.5)%
Public authorities & electric railroads575 725 (20.7)%(20.7)%
Total electric retail deliveries35,495 37,316 (4.9)%(3.5)%
__________
(a)Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

 As of December 31,
Number of Electric Customers20202019
Residential1,508,622 1,494,462 
Small commercial & industrial154,421